DEVELOPMENT OF NATURAL GAS AND OIL
RESOURCES ON THE OUTER CONTINENTAL SHELF
Y 4. H 53: 103-58 _____
Developnent of Natural Cas and Oil... ^AKlJNLr
BEFORE THE
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF
MEXICO, AND THE OUTER CONTINENTAL SHELF
OF THE
COMMITTEE ON
MERCHANT MARINE AND FISHERIES
HOUSE OF REPRESENTATIVES
ONE HUNDRED THIRD CONGRESS
FIRST SESSION
ON
H.R. 1282
A bill to provide enhanced energy security through incentives
to explore and develop frontier areas of the Outer Continen-
tal Shelf and to enhance production of the domestic oil and
gas resources in deep water areas of the Outer Continental
Shelf n£On«OiMMY
SEPTEMBER 14, 1993
Serial No. 103-58
Printed for the use of the Committee on Merchant Marine and Fisheries
U.S. GOVERNMENT PRINTING OFFICE
74-587 ^ WASHINGTON : 1993
For sale by the U.S. Government Printing Office
Superintendent of Documents, Congressional Sales Office, Washington, DC 20402
ISBN 0-16-043350-9
1
DEVELOPMENT OF NATURAL GAS AND OIL
RESOURCES ON THE OUTER CONTINENTAL SHELF
53: 103-58 =^__— —
ent of Natural Cas and Oil... ^AKIJNCj
BEFORE THE
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF
MEXICO, AND THE OUTER CONTINENTAL SHELF
OF THE
COMMITTEE ON
MERCHANT MARINE AND FISHERIES
HOUSE OF REPRESENTATIVES
ONE HUNDRED THIRD CONGRESS
FIRST SESSION
ON
H.R. 1282
A bill to provide enhanced energy security through incentives
to explore and develop frontier areas of the Outer Continen-
tal Shelf and to enhance production of the domestic oil and
gas resources in deep water areas of the Outer Continental
Shelf '" > *"'
SEPTEMBER 14, 1993
Serial No. 103-58
Printed for the use of the Committee on Merchant Marine and Fisheries
U.S. GOVERNMENT PRINTING OFFICE
74-587 ±5 WASHINGTON : 1993
For sale by the U.S. Government Printing Office
Superintendent of Documents, Congressional Sales Office, Washington. DC 20402
ISBN 0-16-043350-9
COMMITTEE ON MERCHANT MARINE AND FISHERIES
GERRY E. STUDDS, Massachusetts, Chairman
WILLIAM J. HUGHES, New Jersey
EARL HUTTO, Florida
W.J. (BILLY) TAUZIN, Louisiana
WILLIAM O. LIPINSKI, Illinois
SOLOMON P. ORTIZ, Texas
THOMAS J. MANTON, New York
OWEN B. PICKETT, Virginia
GEORGE J. HOCHBRUECKNER, New York
FRANK PALLONE, Jr., New Jersey
GREG LAUGHLIN, Texas
JOLENE UNSOELD, Washington
GENE TAYLOR, Mississippi
JACK REED, Rhode Island
H. MARTIN LANCASTER, North Carolina
THOMAS H. ANDREWS, Maine
ELIZABETH FURSE, Oregon
LYNN SCHENK, California
GENE GREEN, Texas
ALCEE L. HASTINGS, Florida
DAN HAMBURG, California
BLANCHE M. LAMBERT, Arkansas
ANNA G. ESHOO, California
THOMAS J. BARLOW, III, Kentucky
BART STUPAK, Michigan
BENNIE G. THOMPSON, Mississippi
MARIA CANTWELL, Washington
PETER DEUTSCH, Florida
GARY L. ACKERMAN, New York
JACK FIELDS, Texas
DON YOUNG, Alaska
HERBERT H. BATEMAN, Virginia
JIM SAXTON, New Jersey
HOWARD COBLE, North Carolina
CURT WELDON, Pennsylvania
JAMES M. INHOFE, Oklahoma
ARTHUR RAVENEL, Jr., South Carolina
WAYNE T. GILCHREST, Maryland
RANDY "DUKE" CUNNINGHAM, California
JACK KINGSTON, Georgia
TILLIE K. FOWLER, Florida
MICHAEL N. CASTLE, Delaware
PETER T. KING, New York
LINCOLN DIAZ-BALART, Florida
RICHARD W. POMBO, California
HELEN DELICH BENTLEY, Maryland
CHARLES H. TAYLOR, North Carolina
PETER G. TORKILDSEN, Massachusetts
Jeffrey R. Pike, Staff Director
William W. Stelle, Jr., Chief Counsel
Mary J. Fusco Kitsos, Chief Clerk
Harry F. Burroughs, Minority Staff Director
Subcommittee on Oceanography, Gulf of Mexico, and
the Outer Continental Shelf
SOLOMON P. ORTIZ, Texas, Chairman
GENE GREEN, Texas CURT WELDON, Pennsylvania
ANNA G. ESHOO, California JIM SAXTON, New Jersey
GREG LAUGHLIN, Texas JACK FIELDS, Texas (Ex Officio)
LYNN SCHENK, California
GERRY E. STUDDS, Massachusetts,
(Ex Officio)
Sheila McCready, Staff Director
Robert Wharton, Senior Professional Staff
Lisa Pittman, Minority Counsel
(ID
CONTENTS
Page
Hearing held September 14, 1993 1
TextofH.R. 1282 193
Statement of:
Fields, Hon. Jack, a U.S. Representative from Texas, and Ranking Minor-
ity Member, Committee on Merchant Marine and Fisheries 12
Flynn, Michael E., Manager, Southeastern Production Division, Exxon
Company, U.S.A 13
Prepared statement 77
Fry, Tom, Director, Minerals Management Service, U.S. Department of
the Interior 3
Prepared statement 31
Juvkam-Wold, Hans, Professor, Petroleum Engineering School, Texas
A&M University 19
Prepared statement 155
Nesvold, Randy, Alaska Area Manager, Phillips Petroleum Company 15
Prepared statement 95
O'Sullivan, Jim, Manager, Brown & Root Seaflo 20
Prepared statement 167
Ortiz, Hon. Solomon P., a U.S. Representative from Texas, and Chairman,
Subcommittee on Oceanography, Gulf of Mexico, and the Outer Conti-
nental Shelf 1
Riggs, John, Principal Deputy Assistant Secretaiy, Office of Policy, Plan-
ning and Program Evaluation, U.S. Department of Energy 5
Prepared statement 51
Rodrigue, Myron, Vice President and General Manager, Aker Gulf
Marine 21
Prepared statement 1°'
Stewart, Robert, President, National Ocean Industries Association 7
Prepared statement 65
Weldon, Hon. Curt, a U.S. Representative from Pennsylvania 2
Wilbourn, Phil, Manager, Central Offshore Engineering, Texaco, Inc 17
Prepared statement 139
Additional material supplied:
Rich, Jim (Shell Oil Company): Statement in support of H.R. 1282 198
Communications submitted:
Flynn, Michael E. (Exxon Company, U.S.A.): Letter of October 7, 1993, to
Hon. Gene Green 93
Fry, Tom (Minerals Management Service, Department of the Interior):
Letter of Nov. 29, 1993, to Hon. Gerry E. Studds, with replies to
questions submitted by Subcommittee following hearing 36
Letters submitted to Hon. Solomon P. Ortiz with replies to questions
submitted by Subcommittee following hearing:
Flynn, Michael E. (Exxon Company, U.S.A.): Letter of October 7, 1993 86
Juvkam-Wold, Hans C. (Texas A&M University): Letter of Oct. 11,
1993 165
Nesvold, Randy (Phillips Petroleum Company): Letter of Oct. 11, 1993 136
O'Sullivan, James F. (Brown & Root Seaflo): Letter of Oct. 29, 1993 185
Pruitt, James C. (Corporate Communications, a division of Texaco):
Letter of Oct. 12, 1993 149
Stewart, Robert B. (National Ocean Industries Association): Letter of
Oct. 5, 1993 71
Taylor, William J., Ill (Department of Energy): Letter of Nov. 15,
1993 - 58
(ill)
DEVELOPMENT OF NATURAL GAS AND OIL RE-
SOURCES ON THE OUTER CONTINENTAL
SHELF
TUESDAY, SEPTEMBER 14, 1993
House of Representatives, Subcommittee on Oceanog-
raphy, Gulf of Mexico, and the Outer Continental
Shelf, Committee on Merchant Marine and Fisher-
ies,
Washington, DC.
The Subcommittee met, pursuant to call, at 2:14 p.m., in room
1334, Longworth House Office Building, Hon. Solomon P. Ortiz
[chairman of the Subcommittee] presiding.
Present: Representatives Ortiz, Green, Laughlin and Weldon.
Staff Present: Jeffrey Pike, Chief of Staff; Tom Kitsos, Chief
Counsel; Sue Waldron, Press Secretary; Sheila McCready, Staff Di-
rector; Robert Wharton, Terry Schaff, Greg Gould, and Chris
Mann, Professional Staff; John Aguirre, Clerk; Harry Burroughs,
Minority Staff Director; Cynthia Wilkinson, Minority Chief Coun-
sel; Richard Russell, Dave Whaley, Laurel Bryant, and Margherita
Woods, Minority Professional Staff.
Mr. Ortiz. The hearing will come to order. And I think we are
having a little disruption as we move along this hearing, within
the next 10 to 15 minutes, but good afternoon.
STATEMENT OF HON. SOLOMON P. ORTIZ, A U.S. REPRESENTA-
TIVE FROM TEXAS, AND CHAIRMAN, SUBCOMMITTEE ON
OCEANOGRAPHY, GULF OF MEXICO, AND THE OUTER CONTI-
NENTAL SHELF
Mr. Ortiz. I would like to welcome all of you here today on
behalf of the Subcommittee on Oceanography, Gulf of Mexico and
the Outer Continental Shelf.
Today, the Subcommittee meets to hear comments on H.R. 1282,
the Outer Continental Shelf Enhanced Exploration and Deep
Water Incentives Act, and other legislative proposals to provide in-
centives for deep water and frontier area OCS development. We
will also be receiving information on current and future deep water
and arctic drilling and production technologies.
The deep water areas of the Gulf of Mexico and the areas of the
Arctic Ocean and offshore Alaska represent some of the best pros-
pects for new oil and gas discovery in the United States. However,
development in these areas has slowed in recent years due to the
high cost of technology required to operate in these extreme envi-
ronments.
(1)
During the 1980's, the price of oil averaged over $30 per barrel.
However, in 1986, the price dropped to under $20 and has remained
there ever since. This drop in price resulted in a decline in domes-
tic oil and gas production, as developmental costs exceeded the
profits that could be obtained from marginal natural gas and oil
fields. This drop in price, along with the associated decline in do-
mestic production, is believed to have been a major factor in the
loss of over a half million jobs within the oil and gas industry over
the past decade.
Since 1991, over 175 oil and gas discoveries have been made in
deep water areas of the Gulf Mexico. These discoveries are estimat-
ed to contain over four billion barrels of oil equivalent. However,
due to the costs associated with developing these prospects, indus-
try has not announced plans to develop most of these discoveries.
With this hearing, the Subcommittee is continuing its review of
the Nation's offshore oil and gas program. The purpose of this
hearing today is to examine the need for incentives to promote the
development of marginal and costly offshore prospects and to
assess the cost to the Federal Government of providing these vari-
ous incentives. Development of these prospects, in an environmen-
tally sound manner, will lead to substantial new job creation and
economic growth for the Nation and will help to reduce our de-
pendence on foreign oil.
I look forward to hearing from the distinguished group of wit-
nesses that we have assembled before us today, and I thank you for
being with us today.
Mr. Ortiz. Now I yield to my good friend and Ranking Member,
Mr. Weldon, for an opening statement.
STATEMENT OF HON. CURT WELDON, A U.S. REPRESENTATIVE
FROM PENNSYLVANIA
Mr. Weldon. Thank you, Mr. Chairman, and I want to thank
you for holding this very important hearing and for our distin-
guished panel for coming and testifying today.
I apologize in advance that we will have to leave. We expect an-
other vote to come about in approximately 15 minutes, so we will
be interrupted, but we will be back again for this very important
session.
Mr. Chairman and our full Ranking Committee Member have
worked for years in finding ways to decrease our Nation's depend-
ence on import oil, and this hearing is simply another step in that
process as we move toward a sustainable national energy policy
which will in the long-term ensure our energy security.
I have always believed in the importance of reliable and environ-
mentally sound energy sources, and since the Gulf War there cer-
tainly has been renewed interest in the part of this body, the Con-
gress, in terms of our energy independence.
In 1992, as you all know, Congress passed and the President
signed the first comprehensive national energy strategy in over a
decade. Although it was a step in the right direction, it is a very
small step toward reducing and establishing our independence on
imported oil.
As a matter of fact, one of the things that Congressman Greg
Laughlin and I have done is formed an energy caucus to work with
our counterparts in the Russian parliament.
Today, the U.S. consumes 29 percent of the world's annual pro-
duction, yet our known reserves account for only 2.5 percent of the
world's oil supply. Those figures are not sustainable.
Conservation obviously plays an important role, and we all have
been strong advocates of alternative fuel programs and conserva-
tion issues. However, conservation alone, many of us feel, is not
going to solve the problem. New sources of energy must be found.
As the recent discovery of a Mars field in the Gulf Mexico illus-
trates, deep and ultra-deep water exploration has the potential to
significantly increase our Nation's oil production. For this reason,
deep water exploration seems to be a promising outlet to travel in
meeting some of our future energy needs.
However, there are some questions, and I hope that we can
answer some of these today, and I would ask the panelists to con-
sider these. Is deep water drilling cost effective? Will the incentives
provided by H.R. 1282 be sufficient to promote deep water explora-
tion? How much will H.R. 1282 cost the taxpayer? Is deep water
drilling an environmentally sound process? These are questions
that I hope we will hear the answers to today from our distin-
guished panelists.
Once again I want to compliment you, Mr. Chairman, for your
leadership and thank all of you for coming in today.
Mr. Ortiz. Let me introduce our first panel, which consists of
representatives from the administration and the oil and gas indus-
try. They are here to speak directly on H.R. 1282 and other propos-
als to provide incentives for offshore oil and gas development.
First is Mr. Tom Fry, Director of the Minerals Management
Service within the Department of Interior. Next is Mr. John Riggs,
Principal Deputy Assistant Secretary for the Office of Policy, Plan-
ning and Program Evaluation within the Department of Energy.
And last but not least is Mr. Bob Stewart, President of the Nation-
al Ocean Industries Association, which is a trade association that
represents roughly 250 companies that are engaged in all aspects of
exploring for and producing oil from the Nation's outer continental
shelf.
Mr. Ortiz. I welcome all of you to the Subcommittee and appreci-
ate you being here with us today. And I think that we can start
with Mr. Fry with his testimony.
STATEMENT OF TOM FRY, DIRECTOR, MINERALS MANAGEMENT
SERVICE, U.S. DEPARTMENT OF THE INTERIOR
Mr. Fry. Thank you very much, Mr. Chairman. It is a pleasure
to be here and to testify before this Committee and to also partici-
pate on this panel with my friend, Mr. Riggs, and Mr. Stewart. We
do appreciate the opportunity to be here.
I have prepared some written testimony which I would — am not
going to read for you today. However, I would ask that that be
made a part of the record.
Mr. Ortiz. Hearing no objection, it will be part of the record.
Mr. Fry. Thank you very much, sir.
Today, I would like to generally talk about the bill that this
Committee has asked us to consider. The bill was drafted, I think,
to encourage offshore development, specifically, deep water off-
shore development. We would support the general goals of that bill.
There are some things that I would like to point out about the bill
that I think might make it more effective, but in general, we do
support measures that will encourage additional production in deep
water and in frontier areas.
I should say that, as I came today, I found that we are having a
sale in the Western Gulf of Mexico tomorrow morning. All the bids
now are in. And I can tell you that last year we had 81 bids on 61
tracts. This year, I can tell you that although we haven't opened
any bids yet so we don't know what they say — we have 197 bids on
157 tracts. That indicates to me that there is some renewed inter-
est in activity in the Gulf of Mexico.
Obviously, bid activity is going to be price-driven. Gas prices are
a little higher today than they were a year ago, so that may have
some effect on what we have seen from the bids. But it is encourag-
ing to me to see additional bidding going on.
To briefly talk about where we find ourself today, the Secretary
of Interior currently has the authority under law to set the royalty
rates prior to leasing. There are certain royalty amounts that the
Secretary cannot go under without coming to Congress for approv-
al, but, generally speaking, the Secretary does have the authority
to set royalty rates on new leases or reduce royalty rates on exist-
ing leases in certain areas. That will be something, depending on
the outcome of this legislation and other legislative proposals, that
we may want to consider on our own.
The second area for consideration is the period of time between
the time a lease is granted and production occurs. For non-produc-
ing leases, it is very unclear as to what the Department's authority
is to engage in royalty reduction during that period. Therefore, we
would be happy to see legislation that would clarify what our au-
thority is. Our Solicitor's office is looking at this and has said we
may have the authority, but we may not have the authority. So it
would be much nicer to have a clear mandate from this legislative
body that tells us exactly what our authorities are in that area.
We clearly have the authority after production begins to reduce
royalties. In fact, I have had the opportunity to participate already
in one such royalty rate reduction case where we have granted a
royalty rate reduction in order to encourage the continuation of
production so that production did not stop.
So that is where we find ourselves in terms of our ability within
the Department to engage in some sort of royalty rate reduction.
The only other thing that I would like to point out initially is
that we think that any bill passed by the Congress should ensure
that there is not a disproportionate gain to any individual party
from a mandatory royalty suspension.
We have done some analysis within the Department of Interior.
We would like to share that analysis with this Committee and also
with the industry so that they can tell us whether our analysis is
correct. But the analysis indicates that a royalty suspension on ex-
isting leases in the Gulf in 200- to 400-meter water depths will
probably not cause additional production. However, we do estimate
that additional production may be encouraged with royalty relief
on two discoveries in a water depth range of over 400 meters.
So we would like to share that information because we want to
make sure that if someone is given a royalty suspension that sus-
pension does not contribute unfairly to their benefit but does en-
courage new production.
Mr. Ortiz. Thank you.
[The statement of Mr. Fry can be found at the end of the hear-
ing.]
Mr. Ortiz. I hate to intervene now, but we do have a vote, and
we have got about nine minutes left. We will go vote and then
after this vote on an amendment we have final passage, so we will
have two votes, but I can assure you we will run back as fast as we
can. Thank you.
[Recess.]
Mr. Ortiz. I am sorry about the interruption, but I can assure
you that there will be more interruptions as we move along.
Now we will have Mr. Riggs, and you can go ahead and start
with your testimony, sir.
STATEMENT OF JOHN RIGGS, PRINCIPAL DEPUTY ASSISTANT
SECRETARY, OFFICE OF POLICY, PLANNING AND PROGRAM
EVALUATION, U.S. DEPARTMENT OF ENERGY
Mr. Riggs. Thank you, Mr. Chairman.
I am Jack Riggs. I am representing the Department of Energy,
and, with your permission, I would like to insert my written text in
the record of the hearing and summarize.
Mr. Ortiz. It will be included for the record, yes, sir.
Mr. Riggs. Thank you.
Let me say at the outset that the Department of Energy agrees
with the Department of Interior's recommendations on H.R. 1282,
and I would like to, in my summary, approach the issue from a
broader perspective.
As the written testimony indicates, the oil and gas industry is
crucial to our economy — as you know as well as anyone, in terms
of its importance to energy security, to the balance of trade and to
the creation of high-tech, high-paying jobs in this country. By
many measures, the loss of jobs, rig counts, increased imports, re-
duced production, the industry has declined over the past decade.
In recognition of that fact, Secretary O'Leary has asked the De-
partment to prepare a domestic gas and oil initiative, and we are
working on that right now, seeking to define proposals for
strengthening the industry in ways that are consistent with the
overall health of the economy and of the environment and the ad-
ministration's deficit reduction plans.
Offshore production is an integral part of the industry. It is re-
sponsible for about 10 percent of our oil production and about 25
percent of our gas production. Offshore production, both deep and
shallow, therefore, will be an important focus of this domestic gas
and oil initiative. We in the Department of Energy are proposing to
establish with Interior a working group to focus on the issues that
are primarily within the jurisdiction of Interior. At the same time,
as we try to stimulate this segment of the industry, we want to
make sure that everything we recommend is consistent with the
highest environmental standards.
One goal — one potential goal of this initiative is to strongly en-
courage energy companies with a choice of prospects for their ex-
ploration and production in the U.S.. That adds value in terms of
energy security, in terms of balance of trade, in terms of jobs, and,
in the case of deep water production, in the development of innova-
tive drilling techniques that not only make currently uneconomic
prospects profitable but that will also help keep U.S. leadership in
this industry.
But the value of producing that marginal barrel or MCF domesti-
cally is not unlimited. Whether to pay a premium and how much
for domestic production is one of the toughest analytical tasks that
we have to undertake. The assumptions that are made will dictate
the conclusions, and these assumptions are frequently made based
more on values than on facts.
If deciding to pay a premium or offer an incentive for domestic
production is tough, the effort to justify incentives for some types
of production over others is even tougher. As Mr. Weldon said in
his opening statement, is deep water drilling cost-effective? That is
one of the key questions on what kind of incentives we need to
offer to bring more on.
In some cases, the very large potential resources will justify a de-
cision to go after the more expensive production, but we learned in
the 1970's and in the 1980's, I hope, to be careful about substituting
our judgment for that of the market, favoring some categories of
gas and oil over others, and we have to approach these decisions
with a rigorous analytical effort. It is with that effort in mind that
we hope to cooperate with Interior and try to define some of these
options.
In the case of H.R. 1282, which would give royalty relief to pro-
duction from certain categories of offshore oil and gas, this caution
informs our judgment and leads DOE to agree with Interior's bal-
anced approach.
First, we agree that some royalty relief may be justified for new
leases in deep water, in part because increased bonus bids and, we
hope, taxes from increased production will largely offset the reve-
nue losses. We will defer to Interior's expertise on the question of
whether 200 meters or 400 meters should be the threshold for this
incentive.
Second, on existing leases, Interior, as Mr. Fry has stated, may
now have the authority to grant royalty relief on a case-by-case
basis, and we presume it will be exercised to provide incentives for
production that would not otherwise occur. We are not eager to
have more free riders than we have new production from such in-
centives. I think Interior's examination of 30 discoveries in the
Gulf and finding that the royalty relief would only affect the pro-
duction decision for two of them provides a powerful cautionary
note to the exercise of this authority.
Finally, on the provision allowing designation of frontier areas
eligible for royalty relief, we again would defer to Interior's exper-
tise and judgment that current law allows them to achieve this
purpose more efficiently.
That concludes my remarks, Mr. Chairman, and I would be
happy to answer questions.
Mr. Ortiz. Thank you very much.
[The statement of Mr. Riggs can be found at the end of the hear-
ing.]
Mr. Ortiz. And now we can move to Mr. Stewart with his testi-
mony.
STATEMENT OF ROBERT STEWART, PRESIDENT, NATIONAL
OCEAN INDUSTRIES ASSOCIATION
Mr. Stewart. Thank you, Mr. Chairman.
I am Bob Stewart with the National Ocean Industries Associa-
tion. Endorsing our statement this afternoon is the International
Association of Drilling Contractors, the International Association
of Geophysical Contractors and the Petroleum Equipment Suppli-
ers Association.
I want to thank you, Mr. Chairman, for inviting us here to testi-
fy. I also want to offer thanks for the gracious cooperation we have
gotten from the Subcommittee staff.
It pains me to have to start out by pointing out that there is an
error in our statement, but I need to correct it for the record. On
the third page of text, in the second full paragraph, there is a sen-
tence that reads, in part, the DRI study found that incentives that
spurred the development of 2 to 7 billion barrels of oil equivalent
should read 2 to 9 billion barrels of oil equivalent. So if we can
make that correction, it would be much appreciated.
Mr. Ortiz. We will make sure that the staff makes the correction
on that.
Mr. Stewart. It is a real pleasure to come up here to address a
proposal, a piece of legislation that proposes to do something for
this industry rather than do something to it. We have discussed
here this afternoon already the level of distress that this industry
has been in, and I am not going to dwell on that any further except
to say that any proposal that is made in the Congress that would
serve in some manner to ease that distress is very welcome.
Mr. Fry has already gone over a good bit of my statement, but I
will touch it very lightly.
The Secretary does indeed have authority under the Outer Conti-
nental Shelf Lands Act to either reduce or eliminate royalties to
prevent premature abandonment of producing properties. It is our
belief that that same section of the OSC Lands Act, namely Section
8(a)(3), also clothes the Secretary with the authority to act prospec-
tively. That is to both reduce or eliminate royalties on a lease
where an exploratory well has been drilled. But when there is a
decision to develop, it probably is going to be a negative because
the economics are marginal, and we believe a very strong and com-
pelling case can be made that the legislation — the OCS Lands
Act — already gives the Secretary that authority.
We would certainly support what Mr. Fry called for, that is,
wiping away any lingering questions about the existence of that au-
thority through legislation. We would have no objection to that at
all.
8
Finally, as far as deep water is concerned, as I say, we find Mr.
Fields' bill very, very welcome. There is no question that the deep
water Gulf of Mexico is basically a new frontier. The geology is less
well-known out there than it is in the shallower Gulf of Mexico.
The infrastructure in many parts of the deep water needs to be
built. It is not there. The costs associated with working in deep
water are necessarily higher.
In answer to one of Mr. Weldon's questions, however, the envi-
ronmental risks associated with deep water development are, in my
view, not any greater than they are in the shallow water. And in
the shallow water this industry's record — environmental record —
has been nothing short of superb.
So, in closing, let me commend the Subcommittee for considering
a piece of legislation of the sort that Mr. Fields has introduced, and
I hope to be able to work cooperatively with the Subcommittee as
well as with the Department of Interior and the Department of
Energy to develop this proposal. Thank you very much.
Mr. Ortiz. Thank you.
[The statement of Mr. Stewart can be found at the end of the
hearing.]
Mr. Ortiz. We are waiting for some of the Members to come
back, but I know that within the next five, six minutes there is
going to be another vote, and I hope that that will be the final
vote.
But I will begin by asking Mr. Stewart a question here. What
effect will the proposed incentives have on industry's willingness to
develop deep water or marginal areas? And what can be done to
stimulate deep water or marginal areas without legislation?
Additionally, do you feel that providing royalty relief will induce
enough new development that would not otherwise take place to
make such a proposal justified in terms of protecting Federal reve-
nues?
Mr. Stewart. I think, Mr. Chairman, that if this program is de-
signed properly you should be able to avoid offering incentives to
projects that would go forward anyway. That is not the objective
here.
The objective, as in the case with the exercise of the secretarial
authority that is already there, is to either prolong existing produc-
tion or to prompt new production to come on stream that would
not otherwise have been done.
There is, in that case, in our view, no loss of revenue to the Fed-
eral Government at all. You are forgiving royalties that would not
have been paid anyway because either the project would have been
terminated or never started. So you really haven't lost anything.
On the other hand, if you either produce a new project or extend
an old one, you continue to create a line of tax revenue to the Fed-
eral Treasury. You also have an impact on jobs that is positive. So
even though some may say — and we have talked in part about
tax — correction — tax credits needing to be a part of the package in
very deep water. People roll their eyes when you mention that and
say, well, it is not possible. It is not politically doable.
You can look at the economic wallop that some of those projects
produce — and there is an example of one of them in our written
statement in terms of jobs, in terms of hundreds of contracts going,
in the case of the one project we cite to 33 different States. The
economic wallop is sufficiently large that you may look at relief
and tax credits and think it is a bargain for the American people.
Mr. Ortiz. Thank you.
Mr. Riggs, how does the proposed legislation fit into DOE's na-
tional energy initiative and are there other ways to stimulate do-
mestic offshore oil and gas exploration, development and produc-
tion?
Mr. Riggs. Mr. Chairman, this is clearly one potential option
that would be the type of thing that could be included in the do-
mestic gas and oil initiative and one that is being examined in our
current discussions. At this point, they are still in the discussion
stage, and I can't say that it will or will not be included. We clear-
ly want to cooperate closely with Interior on items dealing with
public lands.
Other examples of things that could stimulate additional produc-
tion include: additional flexibilities in royalty and bonus pay-
ments— again, Interior has the expertise here; potentially a sliding
scale of royalties with a reduction up front and higher royalties
later on if a discovery is a large one; incentives for the use of new
technologies that might bring on some of these more difficult fron-
tier areas; and the use of technology from DOE's national laborato-
ries.
There is a lot of excitement in the industry, I believe, and in the
Department about 3D seismic technology, and it is my understand-
ing that some of the information available from previous seismic
shoots in the Gulf could be more fully utilized with better comput-
er technology that we may have available through Sandia or Los
Alamos, some of the DOE labs.
In general, I would say that, in working with the Department of
Interior, we would hope to identify options that would be useful in
this area.
Mr. Ortiz. I think I am going to have to recess for a few minutes.
I hope that this is the last vote, and I am pretty sure that some of
the other Members will be back, so the Committee will stand ad-
journed for a few minutes.
[Recess.]
Mr. Ortiz. Again, somebody lied to me. They said there is one
more vote somewhere within the next 15 to 20 minutes, and I
really apologize for all the inconveniences that we have had
throughout the hearing. Some of the other Members should be
coming back soon, I hope. We just have my distinguished — my good
friend and colleague from Texas, Mr. Green.
Mr. Fry, I am going to ask you a question. What impact will
these incentives have on the Federal budget deficit? Now, how do
the short-term revenue losses from royalty relief compare with the
potential overall increases to OCS royalty from these revenues —
maybe you can elaborate a little bit on that.
Mr. Fry. Yes, Mr. Chairman. I am not sure I know the ultimate
answer to that question, but I would like to share some thoughts
on that.
I think in the initial years, in the first couple of years of a pro-
gram like this, it will probably have a positive impact on deficit re-
duction because I think you will see — to the extent that there are
10
reduced royalties, you will end up seeing increased bonuses. So
when we have lease sales, people will probably bid a little higher
for tracts because they know they are not going to have a royalty
obligation.
But our analysis has indicated that in the long-term, in the out-
years — we are talking about throughout the life of the produc-
tion— under the current configuration of the bill, there would prob-
ably be a substantial decrease in royalty revenues paid to the Fed-
eral Government because of the lack of the royalty being paid. So
when you look at the revenue impacts in the greater scheme of
things, the bonuses are a very small portion of the revenues that
are received by the Federal Government, and most of what is re-
ceived is on the royalty side.
Our analysis indicated that some of the projects under some of
the different types of legislation we have looked at might never get
to the point where a royalty provision or royalty ever kicked in, so
there could be substantial losses in the long-term if we do not
structure a statute or a program that only encourages people to go
forward on a real incentive basis rather than on some other basis.
Mr. Ortiz. You know, I can understand the loss of revenue, but I
think that Mr. Stewart made some good points as well. You know,
of course, there is a lot of uncertainty out there, but it would be
great if we didn't have to be so dependent on foreign oil and if we
could see more people employed. But there is a gray area out there.
But before I go any further, I would like to yield to my good
friend and colleague from Texas, Mr. Green, and see if he has got
any other questions.
Mr. Green. Thank you, Mr. Chairman.
Again, I apologize to our panel and — for having so many votes
today. It seems like every 20 minutes, as soon as we come back, we
have to go back over and vote.
This issue is important to me, I know, just like our Chairman,
because of the districts that we represent. I have Port Houston and
the east part of the county particularly, and we have a great many
people who need their livelihood or develop their livelihood from
offshore drilling and offshore technology. And I noticed in the —
that in 1991 there were 175 discoveries in deep water areas and
only 23 were developed, and I imagine cost is the biggest problem
because of deep water.
But also knowing what is happening to the market now — and
some of us are concerned. We don't want to see what is happening
again happen to us a few years ago. But could you just tell us why
only 23 were chosen? If it is cost or if it is volatility of the market
or just share it with the Committee.
Mr. Stewart. I will take a shot at it.
I think, Mr. Green, that you want to ask that question to the
next panel because you have got actual companies with deep water
prospects there, but I would speculate with you that at least some
of those possible projects are not being developed because they are
marginally economic. The reserves that have been found out in the
deep water are, in many cases, quite large, but because you lack
the infrastructure of pipelines and because it is very difficult — not
difficult but expensive — to work in deep water, the economics have
to be right.
11
There are also some risks involved in deep water — geologic risks
that don't exist so much in \he shallower water where the geology
is better understood.
Mr. Green. You think if prices would be a little better, those
risks would be worth taking?
Mr. Stewart. That is right. You have to have two things in busi-
ness. You have to have access to resources, and you have to have
your economics right. If you get both those right, something will
happen.
Mr. Green. Let me ask another one.
Again, the concern a lot of us have — and we survived in offshore
in Texas for a number of years because we recognized there are
risks — but does deep water or frontier area drilling production pose
additional environmental risks and does this legislation impact any
existing environmental protections or laws or regulations or per-
mits?
Mr. Stewart. I don't believe it does. I think the same technol-
ogies that have created or allowed the industry to create the safety
record that it has, safety both in terms of human safety and envi-
ronmental safety in the shallower parts of the Gulf Mexico, those
technologies continue to get better. They will be used to the fullest
extent no matter what the water depth because it is in our interest
to operate safely, not the other way around. And I don't believe
there is anything in the legislation that would change that.
Mr. Riggs. If I could add a point to that.
I think it is worth expanding the focus a little bit and thinking
about the environmental impact, to the extent that we are able to
find oil through offshore drilling. If we back out imported oil, we
are avoiding tankering oil through our waters, and that is where
the spills have been coming. So it is an environmental improve-
ment if we find the oil there.
We may find natural gas — and I think we all realize natural gas
is an environmentally superior fuel. I believe about 70 percent of
what we find in the offshore area is gas.
So there are some revenue questions to be answered on the effec-
tiveness of the bill, but I think environmentally it is not a problem.
Mr. Green. I made that argument, too, about natural gas as a
legislator, and I am trying to make it now as a freshman in Con-
gress to some of my colleagues here.
One last question if I may, Mr. Fry, and it is good to see you. I
know we met last week. And welcome to Washington.
Mr. Fry. Nice to be here.
Mr. Green. Has any decision been made on the revised definition
of deep water for the purpose of reducing the OCS royalty rates?
And should bonding requirements be higher for deep water or fron-
tier area drilling rigs or production facilities? I know — didn't you
and I talk last week — there is a lease sale shortly?
Mr. Fry. Yes, and we have now received all the bids. They had to
be in by 10 o'clock this morning central time. And I am going to
New Orleans after this meeting and will watch my first sale, which
will occur tomorrow. As I reported to the Committee earlier, we
have 197 bids on 157 tracts, which is an increase over the last two
years, or more than double what we had two years ago.
12
Mr. Green. Great. Are there — have there been discussions about
reducing the outer continental shelf royalty rates maybe to encour-
age production?
Mr. Fry. We have had some discussions about that, and we feel
that under existing law, the Department of Interior does have,
along with consultation with the Congress, the ability on new
leases to do some deep water reductions, or "pre-lease" reductions.
We are going to look at that very hard for future sales, to try to
encourage additional leasing in the deep water.
You also asked about the bonding. We have just come out with a
new bonding rule which did increase the general bonding require-
ments because we want to make sure the taxpayer is not negative-
ly affected at the end of the lease life with many of these projects.
The rule also still allows the Department of Interior to have a
great deal of flexibility in terms of those bonding amounts. If we
determine that more bonding is required, we have the ability to
raise the bonding requirement.
The opposite is also true. If it is determined that the bonding re-
quirement is too steep, based on the risk involved, we have the
ability to lower those requirements. So we have a rule in effect, but
we also have the ability to look at it on a case-by-case basis, be-
cause it certainly is more expensive in the deep offshore to aban-
don a platform. And so we are going to have to revise our estimates
on that, but right now we feel pretty comfortable with our new
rule.
Mr. Green. I saw our friend, Bob Armstrong, Saturday when the
President was in Houston, and he was on his way back up here,
something about a soccer game I think or something. But anyway,
thank you, Mr. Chairman.
Mr. Ortiz. Thank you. We have heard some very interesting tes-
timony, and I am sorry that we have been interrupted several
times.
At this point, I would like to include the statement of my good
friend, Jack Fields, for the record. And hearing no objection, it will
be inserted in the record.
[The statement of Mr. Fields follows:]
Statement of Hon. Jack Fields, a U.S. Representative from Texas, and
Ranking Minority Member, Committee on Merchant Marine and Fisheries
Mr. Chairman, I want to thank you for scheduling this hearing today, and look
forward to hearing testimony on H.R. 1282, the Outer Continental Shelf Enhanced
Exploration and Deep Water Incentives Act, that I introduced with several of our
colleagues earlier this year.
Mr. Chairman, I appreciate the opportunity you have given us to hear the views
of the new Administration and representatives of the oil and gas industry on deep
water incentives. I believe that the deep water areas of the Gulf are the future for
our OCS oil and gas extraction program. It is important that we encourage and sup-
port our domestic industry to make the technological advances that are necessary to
explore these deep water areas.
I look forward to hearing input not only on my bill, H.R. 1282, but also on what
measures are needed to enable further exploration and development of deep water
fields, especially those in the Gulf of Mexico.
Several of our witnesses today will be testifying that the Fields' bill is the first of
many steps needed to encourage the production in deep water. I appreciate their
candor and hope that this hearing will give the witnesses a chance to tell us what
they feel would be necessary to keep our domestic industry interested in staying in
U.S. waters.
13
I hope that the representatives from the Administration will listen carefully to
our witnesses, and take these comments back to their respective departments. We
need to work hard to make sure that the energy extraction industry in this country
does not continue to export jobs to other areas of the world, where they are more
welcome than in the U.S.
Thank you, Mr. Chairman. I look forward to hearing the testimony from today's
witnesses.
Mr. Ortiz. That concludes the testimony for this first panel, and
I would like to thank both the Federal agencies and NOIA for
coming here today and sharing their insights on the legislation.
And we can assure you that we would like to work with you and
hope that we can implement some type of legislation that would be
beneficial, you know, to everybody. Again, thanks for being with us
today.
Mr. Fry. Thank you, Mr. Chairman.
Mr. Ortiz. We can start getting ready for the second panel. I
would like now to introduce the second panel which consists of rep-
resentatives from the oil and gas industry arid academia. This
panel will present information associated with current deep water
and arctic activities, technology and research.
First, we will hear from Mr. Michael Flynn, Manager of the
Southeastern Production Division of Exxon Company, U.S.A.. Mr.
Flynn will be providing information on current deep water develop-
ment technologies.
Then we will hear from Mr. Randy Nesvold, Alaska Area Manag-
er for Phillips Petroleum Company. Mr. Nesvold will be presenting
information on current arctic development technologies.
Next we will hear from Mr. Phil Wilbourn, Manager of Central
Offshore Engineering for Texaco, Incorporated. Mr. Wilbourn will
be talking about an industry cooperative program known as Deep
Star.
And next will be Dr. Hans Juvkam-Wold, a professor with the
Petroleum Engineering School of Texas A&M University, who will
be providing a review of deep water and arctic OCS technology and
research.
Then we will hear from Mr. Jim O'Sullivan, Manager of Brown
& Root Seaflo. Mr. O'Sullivan will provide an overview of the SEA-
PLAN computer program.
Last, but certainly not least, is Mr. Myron Rodrigue. He is Vice
President and General Manager of Aker Gulf Marine, a company
that operates two fabrication yards which service the offshore oil
and gas industry, particularly deep water projects.
STATEMENT OF MICHAEL E. FLYNN, MANAGER, SOUTHEASTERN
PRODUCTION DIVISION, EXXON COMPANY, U.S.A.
Mr. Flynn. Thank you very much, Mr. Chairman.
My name is Mike Flynn. I manage Exxon U.S.A.'s Southeastern
Production Division located in New Orleans, LA. We are responsi-
ble for Exxon's producing activities, both on-shore east of Texas
and in the Gulf of Mexico. I appreciate the opportunity to discuss
incentives to encourage exploration and development in the Deep-
water Gulf of Mexico, which I am going to refer to as the Slope in
my discussion.
14
Our division employs 1,500 people directly. Two-thirds of our pro-
duction comes from the Gulf of Mexico. Our responsibilities include
developing opportunities in technologically challenging areas such
as the Slope. As indicated by the Department of the Interior, the
Gulf of Mexico Slope is thought to contain the largest accessible
undiscovered petroleum resource in the nation. Remaining undis-
covered resources are estimated to be 4 billion barrels of crude and
44 trillion cubic feet of gas. On an energy equivalent basis, this
compares to the 12 billion barrels of liquids in the Prudhoe Bay
Field.
The petroleum industry has already discovered 5 billion equiva-
lent barrels in about 90 fields. Half the discovered resource is natu-
ral gas. 80 percent of the discovered volumes are believed to be
beyond the limit for conventional platforms. Today it is unclear
how much exploration and development effort will be focused on
the Slope. Only 10 fields containing less than one billion barrels
are currently producing or committed to development.
Let me provide some background on the high risks and costs by
describing Exxon's activities on the Slope. Our Lena Field, located
in 1,000 feet of water, developed 75 million barrels using industry's
first guyed tower in 1984. The Lena reservoirs were much more
complex than expected. Absent royalty and tax incentives, this
field would not be developed today, or it would be developed using
a smaller platform and recovering fewer reserves.
Alabaster and Zinc are our most recent developments and we
have hosted numerous government officials on visits to that site.
Existence of a nearby underwater knoll at Alabaster allowed devel-
opment with a conventional platform in 470 feet of water. Zinc is
in 1,500 feet of water six miles away and was developed with a
subsea production system. If not for the fortuitous knoll, develop-
ment would not have been possible without royalty and tax incen-
tives.
Our next step is a large one because the seven discoveries we
have yet to develop are in water depths greater than 2,500 feet. De-
velopment costs are high and lead times are long, requiring large
investments many years in advance of revenues.
Industry experience is still very limited with the complex geology
found on the Slope. In this difficult environment, years are often
required for seismic studies, delineation drilling, and careful plan-
ning. Single field investments can range between 1 to $2 billion,
which is greater than the net assets of all but about 50 U.S. oil and
gas companies. Even after an investment is made, sustainable pro-
ducibility can be uncertain. That was experienced by Placid at its
Green Canyon development, which was an economic failure.
In these water depths the threshold size for an economic discov-
ery can vary, but is generally 100 million barrels. We estimate half
the volume discovered to date is contained in fields smaller than
this, which will require creative approaches. For example, in order
to lower costs, several fields may be combined into a single develop-
ment. Let me further illustrate the challenges faced in deeper
water by discussing two currently undeveloped prospects.
The Ram/Powell Field is located in 3,300 feet of water. There are
currently no developments in this water depth or beyond world-
wide. The three field owners believe total costs, if developed, could
15
be around one billion dollars using a tension leg platform. Howev-
er, there is still optimization being pursued. There are lower qual-
ity reservoirs that we may not develop initially, and possibly not at
all, given the current tax and royalty system, as well as risks.
Another field that we have under evaluation is located in 3,000
feet of water in the Green Canyon area. To date only the discovery
well has been drilled. One potential development alternative for
the prospect is as a satellite to a nearby, existing platform when its
production declines. Our ability to take advantage of this type of
opportunity is dependent upon flexible lease terms.
Even with added flexibility, royalty and tax incentives are still
needed to encourage industry to invest in deepwater projects.
Alone, H.R. 1282 would not be sufficient. Additional incentives
such as the deepwater production tax credit of $5 per equivalent
barrel contained in Senator Breaux's bill are needed to encourage
substantial additional activity in the near-term.
Incentives that are nondiscriminatory between producers, struc-
tured to reward successful efforts, and apply to new production
from existing and new deepwater leases can be effective in the
near-term and benefit the Nation as a whole. They are results ori-
ented, encourage investment, create jobs, and government can re-
ceive more revenue over time than it potentially gives up.
In closing, I want to say we appreciate the opportunity to present
this technology to the Subcommittee. We believe that royalty
relief, combined with a production tax credit, together can impact
Gulf of Mexico Slope development in a meaningful way. Also work-
ing with industry and the MMS, we believe lease term flexibility
can continue to be improved to allow efficient, economic resource
development. Thank you very much.
[The statement of Mr. Flynn can be found at the end of the hear-
ing.]
Mr. Ortiz. Thank you.
Mr. Nesvold.
STATEMENT OF RANDY NESVOLD, ALASKA AREA MANAGER,
PHILLIPS PETROLEUM COMPANY
Mr. Nesvold. Thank you, Mr. Chairman.
My name is Randy Nesvold. I am Alaska area manager for Phil-
lips Petroleum Company's North American Exploration and Pro-
duction Division located in Houston, Texas.
My responsibilities include overseeing Phillips' investments and
activities in the Prudhoe Bay and Point Thomson fields in Alaska's
North Slope, as well as the recent Sunfish discovery in the Cook
Inlet and the Kuuvlum discovery in the Beaufort Sea. I have 12
years of experience with Phillips and have been assigned to Alaska
operations for the last 5 years.
Phillips is an integrated oil and gas company that has for the
past 76 years been located in Bartlesville, Oklahoma, where it was
founded in 1917. We presently employ more than 21,000 people
worldwide and we are involved in all aspects of the petroleum busi-
ness from exploration, production and refining, to transportation,
marketing and research.
16
Phillips has been a leader in opening new frontiers for oil devel-
opment, including our initial participation in development of the
North Slope, and Phillips discovery of the Ekofisk field which
opened the door for development of the North Sea. Phillips appreci-
ates the invitation from the Committee to testify on the subject of
arctic exploration and production technologies.
First, some background on the Alaska Beaufort Sea. Since the
late 1960's, over 60 exploratory wells have been successfully drilled
in Beaufort. Unfortunately, due to low oil prices, high operating
cost and the harsh operating conditions of the Beaufort Sea, none
of the exploratory drilling to date has resulted in discovery of an
offshore field that is economic to develop, except for the shallow
water Endicott, Point Mclntyre and Niakuk fields located adjacent
to Prudhoe.
To transform the Beaufort Sea from an exploration play to an ec-
onomical producing trend, operators will have to overcome environ-
mental, technological and timing challenges presented by the
deeper waters of Beaufort Sea. Environmental and technological
hurdles can most likely be overcome, but timing is critical. With
declining production from existing North Slope fields, the TransA-
laskan pipeline and related North Slope infrastructure may
become uneconomic to operate as early as 2014.
The Arctic environment poses unique challenges. Operators must
contend with temperatures that plunge to minus 65 degrees below
zero, two months of total darkness during winter operations, and
with the migration patterns of the bowhead whale.
Current technology is well developed to handle arctic explora-
tion. Under the "Drilling" section of my written testimony you will
find a series of pictures exhibiting the systems currently capable of
operating in the Beaufort Sea, everything from a man-made gravel
islands to specially designed ice breaking drilling systems. But the
cost of exploration is expensive. Well costs range from a low of $20
million for a spray ice island to over $80 million for a well drilled
from a floating drilling system.
Once an offshore field is discovered, options for bringing a field
into production are less defined, but initial developments will
likely be based on extensions of existing drilling technology.
Several production platform designs have been proposed, and in
the "Production" section of the handout you will find conceptual
drawings of some of the proposals.
The cost of installing a permanent production facility will be
enormous. Estimated development costs are tabulated in the writ-
ten testimony. The bottom line is that if a major oil field is discov-
ered in the Beaufort, development costs could approach $8 billion
or more.
The biggest obstacle facing our operations is not the harsh envi-
ronment or technological limitations, however. It is timing. Cur-
rent drilling technology only allows an operator to drill one or pos-
sibly two deep water wells per year in the deeper Arctic waters.
Once the discovery is made it will take at least nine to 10 years to
delineate, design, build and install an offshore facility. It is impera-
tive that major discoveries be made in the Arctic in the very near
future in order to take advantage of the existing transatlantic pipe-
line system and other North Slope infrastructure.
17
Even with the challenges posed by the offshore Arctic, Phillips is
confident new technologies will be developed to meet the chal-
lenges just as we were when Phillips first began exploring on the
North Slope and in the North Sea.
Thank you, Mr. Chairman, for your invitation to allow us to pro-
vide the Subcommittee with information on Arctic technology. We
would be happy to address any questions you have.
[The statement of Mr. Nesvold can be found at the end of the
hearing.]
Mr. Ortiz. Thank you.
Mr. Wilbourn.
STATEMENT OF PHIL WILBOURN, MANAGER, CENTRAL
OFFSHORE ENGINEERING, TEXACO, INC.
Mr. Wilbourn. Mr. Chairman, I appreciate the opportunity to
discuss deepwater technologies with you today.
What I would like to address is the fact that oil today is selling
for $20 a barrel. Our assessment of deepwater is that it costs $10
per barrel to get the oil to the refinery. We are talking about the
$10 differential. I am talking about in this technology presentation
a way of reducing that $10 per barrel lifting cost to in the neigh-
borhood of $8 per barrel, so we can grow this differential. You have
heard discussions earlier that address the royalty issue and the tax
relief issue.
Specifically I would like to review the Texaco-sponsored Deep-
Star project. DeepStar is an industrywide cooperative effort focused
on identification and development of economically viable, low-risk
methods to produce hydrocarbons from deepwater tracks in the
Gulf of Mexico.
Presently we have 15 operators as participants and 30 service
companies as contributors. Joining together in this industry cooper-
ative effort, progress is being made toward the common goal of
having an economic deepwater production strategy and the neces-
sary technology and equipment ready for field use by the latter
half of this decade.
The major technology goals for DeepStar include evolving a deep-
water concept capable of producing in water depths up to 6,000
feet; accommodation of a broad range of produced fluid properties
and rates from various reservoir types; subsea satellite production
to host platforms up to 60 miles away; installation of the subsea
facilities in a staged manner; remote-operated vehicle installation
and maintenance capability; and all production operations remote-
ly controlled from the host platform or potentially in early field
life, from the drilling vessel.
The DeepStar concept employs a phased development strategy. It
also focuses on a system approach versus a random component
design. The three major stages of the development approach are;
(1), the exploration and delineation drilling phase; (2), the evalua-
tion and early production phase; and (3), the full field development.
Under the DeepStar concept, initial deepwater subsea production
operations will attempt to use existing platforms as host-processing
facilities. As confidence in the deepwater concept is established, a
18
staged expansion of the subsea facilities would be initiated. This
may require the construction of a new dedicated processing center.
Once established, the center would be capable of handling pro-
duction from a number of other deepwater prospects within a 60-
mile radius. The existence of new deepwater infrastructure will fa-
cilitate the commercial development of small fields which would
normally not be considered economically attractive on their own.
An opportunity exists here for the industry to again incorporate
and establish joint processing centers that can service an entire
region. During Phase I of technology studies, the DeepStar team
documented and evaluated the capability, cost and availability of
basic components and subsystems that would potentially be re-
quired for remote subsea development through a series of studies.
The results of specific investigations in these areas provided recom-
mendations as to the best types of components for use in deepwater
subsea systems to meet an actual field development within the
next two to five years.
The Phase II work program for 1993 and 1994 is broken into 10
major technology focus areas. Work in each focus area is overseen
by a chairman and a technical committee consisting of representa-
tives from each of the participating companies.
One of the unique aspects of DeepStar is that participants are
sharing prior technical research in an effort to "quantum leap"
technology development in these key focus areas and to do so at
minimum cost.
A number of regulatory-related barriers exist for development of
the deepwater Gulf of Mexico. Representatives of the DeepStar par-
ticipating companies have been meeting on a monthly basis with
the MMS to discuss technology issues and current regulations in an
effort to identify areas where existing regulations are not in step
with technology capabilities.
Areas of discussion have included production monitoring and
testing, underwater safety valves, shut down requests, suspension
of production, and subsea installation maintenance and repair.
Extended well test operations have also been the subject of nu-
merous discussions. Second only to reservoir questions, produced
fluid problems are seen as a major barrier to economically viable
production from the deepwater gulf.
Of special concern to the participants is parafin production fol-
lowed closely by hydrate formation and asphaltine production.
Single largest expenditure for deepwater developments will be well
drilling and completion cost. This activity alone accounts for be-
tween 40 and 70 percent of the cost of deepwater developments.
Cost control and reduction is critical to the effort to make the
deepwater gulf commercially viable. The participants are focused
on identifying those actions that can be taken to reduce drilling
completion and intervention costs.
DeepStar is defining the way operators, suppliers and govern-
ment agencies can work together to promote development in tech-
nically challenging environments such as the deepwater gulf. Many
technology issues critical to the progress of deepwater development
are being addressed and innovative development concepts and ap-
proaches are being evolved.
Thank you.
19
[The statement of Mr. Wilbourn can be found at the end of the
hearing.]
Mr. Ortiz. Thank you, sir.
Now we can turn to Mr. Juvkam-Wold. You can proceed with
your testimony.
STATEMENT OF HANS JUVKAM-WOLD, PROFESSOR, PETROLEUM
ENGINEERING DEPARTMENT, TEXAS A&M UNIVERSITY
Mr. Juvkam-Wold. Thank you, sir. I would like to talk about the
technology and research as it relates to the Outer Continental
Shelf and the Arctic. I would like to make my comments in terms
of specific problems and solutions.
The main problem we are faced with here is that we consume a
lot more oil than we produce. And our consumption is growing and
our production is decreasing; in fact, decreasing at the rate of
about 3 to 4 percent per year. We make up the difference overall
with oil imports to the States, where we are now importing close to
half of our crude oil, and our imports account for perhaps two-
thirds of our trade balance deficit.
We need to do something about that, but what caused this? What
are the reasons for this problem? The problem is that costs, aver-
age costs to find, develop and produce hydrocarbons in the U.S. are
higher than overseas. These costs are especially high in the deep-
water Outer Continental Shelf and in the Arctic.
The proposed solution of providing financial incentives in terms
of royalty relief as proposed in this bill I think will help to over-
come the difference in cost and will result in somewhat more U.S.
oil production. I am not sure it will be enough.
Now to some specific technical problems and solutions. On the
Outer Continental Shelf, one of the major problems on the deepwa-
ter Outer Continental Shelf is that the cost of production platforms
is excessive. Each prospect or project cannot handle the cost of one
production platform in deepwater unless the petroleum reserves
are very, very large.
Now, one approach to solving this problem is to develop lower
cost platforms through the use of new materials and through opti-
mization of size and shape of the platforms and standardization of
design. This is the approach taken by the Offshore Technology Re-
search Center jointly operated by Texas A&M University and the
University of Texas.
Another approach is to reduce the number of platforms and to
place the platforms that you do need in shallower waters. This
would require the use of subsea completion and long production
lines, and of course is the approach taken by the Texaco DeepStar
project we just heard about.
Both these two approaches may be necessary. I want to say that
in trying to come up with solutions here, there has been excellent
cooperation between industry, academia, and governmental agen-
cies. Perhaps unprecedented cooperation.
Now for a few words about the Arctic. The primary problem, as I
see it, in the Arctic offshore is the presence of moving sea ice
which results in very high forces on offshore structures. This re-
sults in a need for very large, very costly, very heavy structures. So
20
costly, in fact, that only the very largest petroleum deposits would
justify development economically.
Now, research efforts are focused in the Arctic on learning more
about ice and ice forces. But more research is needed in defining
the magnitude of the forces we expect when ice collides with off-
shore structures.
I have made a short list here of R&D requirements, and this is
by no means a complete list, but this is all I am going to have time
for. We need, obviously, to be able to install subsea completions in
much deeper waters than we have done to date. We are going to
need subsea multi-phase pumps, subsea separators. We also need
lower cost deepwater production platforms, and of course a lot of
work is being done in this area.
We need to learn more about blowout prevention in deep waters.
We need lower drilling costs. This is essential. And as far as the
Arctic goes, we need to learn more about ice properties and ice
forces.
And as a closing comment, I would like to say that the U.S. is in
the process of losing its position of leadership in oil field technology
primarily because of inadequate long-term research.
Thank you, Mr. Chairman.
[The statement of Mr. Juvkam-Wold can be found at the end of
the hearing.]
Mr. Ortiz. Thank you.
Mr. Sullivan.
STATEMENT OF JIM O'SULLIVAN, MANAGER, BROWN & ROOT
SEAFLO
Mr. O'Sullivan. Mr. Chairman and Members of the Committee,
thank you for the opportunity to appear before you to present in-
formation pertinent to your consideration of incentives for oil and
gas activities on the Continental Shelf in the United States.
My name is Jim O'Sullivan. I am the manager of Brown & Root
Seaflo. Brown & Root has worldwide operations in a broad range of
energy services including marine engineering, construction and in-
stallation services. The Brown & Root Seaflo unit specializes in off-
shore field development flange and deepwater production technolo-
gy.
I have with me today written testimony which is clarifying and
more extensive than the document supplied to the staff earlier, and
I ask that it be substituted for that earlier document and be en-
tered into the record along with my brief oral testimony.
Mr. Ortiz. Without objection, it will be included in the record.
And I will also say for the other witnesses that might have addi-
tional statements, if do you have statements, just give them to the
staff and they will appear in the record. Thanks.
Mr. O'Sullivan. The written testimony is derived from an in-
house study that examined the prospects for deepwater field devel-
opments in order to better plan Brown & Root's activities. Let me
mention here that the Sea Plant computer program was used in
econometrics modeling. I bring that up because you mentioned pro-
gramming earlier.
21
The results of the study concur with the observations of the
other speakers here today and is presented to the committee as a
generalized framework for viewing deepwater Gulf of Mexico devel-
opments. I will share with you several brief general conclusions
that can be drawn from the study.
Flat oil price forecasts will require deepwater developments to be
developed with capital investments below $8 per barrel of recover-
able reserves. You have to add the daily operating expenses, which
are about $2 to $3 a barrel. That is where you get the $10 number.
To do this, reservoirs will have to perform better than those on
the shallower Gulf of Mexico shelf. Wells should produce at or
above 3,000 barrels per day and each well should drain between 5
million wells or more. Both these rates exceed typical well perform-
ance by around 50 percent, and represents a risk the operator must
bear.
The cost of the production facility represents around half the
total installed cost of development and offers the most opportunity
for cost reductions based on technology advancements. Drilling and
completion of wells, transporting the product by pipeline represent
roughly about the other half of the installed cost, but are more
driven by geological and commercial issues rather than technologi-
cal ones.
Minimizing surface facilities at the deepwater site offers the best
potential cost savings. In general, this involves sharing the process-
ing facilities at one location between two or more field develop-
ments and might indicate the need for a regional development ap-
proach. This is very similar to the work that DeepStar is pursuing.
A final observation from the study is that technology develop-
ments are needed to verify the extension of current technology into
deeper water. Cost contingencies are a necessary means for manag-
ing technical uncertainties associated with extension of current
technology into deeper water.
However, when you apply these contingencies, every 1 percent in
projected estimated development cost increases the reserve require-
ment by 2 percent. So the cost sensitivities are quite an issue. In-
vestments in technology development will reduce the downside un-
certainties and improve the overall project economics.
This concludes my brief oral testimony. I hope the written and
oral testimony will be of service to this committee in reviewing the
need for incentives to develop Gulf of Mexico oil and gas resources.
[The statement of Mr. O'Sullivan can be found at the end of the
hearing.]
Mr. Ortiz. Thank you, sir.
We now have a good friend, Mr. Myron Rodrigue. You can pro-
ceed with your testimony.
STATEMENT OF MYRON RODRIGUE, VICE PRESIDENT AND
GENERAL MANAGER, AKER GULF MARINE
Mr. Rodrigue. Thank you, Mr. Chairman. I guess I have to note
I am a transplanted Texan.
Good afternoon, Mr. Chairman, Members of the Subcommittee. I
appreciate the invitation to testify.
22
I am Vice President and General Manager of Aker Gulf Marine.
We operate two fabrication yards in south Texas, one in Ingleside,
one in the Aransas Pass, to service the offshore oil and gas indus-
try.
Our company is a relative newcomer to the industry. In 1984, our
parent companies, Peter Kiewit Sons, Inc., investigated the offshore
fabrication market and determined the OCS was an area which
would experience growth and a need for additional capacity for
deep water platform construction.
Soon after opening our doors in November of 1984, we secured a
contract to fabricate Mobil's Green Canyon Block 18 structure,
which is now installed in 760 feet of water. At the same time we
formed a joint venture to bid Shell's Bullwinkle structure. This
joint venture was successful in securing the contract. Fabrication
of Bullwinkle, to date the world's largest fixed offshore structure,
installed in 1350 feet of water, began in the summer of 1985. This
project took three years to build.
Together with the Mobil job and several small other projects we
secured, our total employment reached 1,200. If we include subcon-
tractors working directly for us and our clients, total employment
at our facilities was over 1600. The point is that deepwater offshore
development means jobs for the United States.
I became Vice President and General Manager in December of
1987, just six months before we loaded out the Bullwinkle struc-
ture. At that time our total craft employment was down to 200,
with no other backlog on the books.
During the first two years as general manager, my priorities
were quite diverse. One was to determine the lowest cost option to
get out of business. The other was to secure enough work to stay in
business.
You can see our business is quite cyclical. It is very difficult to
justify the capital investment required to service the deepwater
sector of the offshore industry when the market is so unpredict-
able. This unpredictability is not because our clients are unwilling
to explore and develop our offshore resources.
We have invested over $50 million in our plant and equipment.
Almost all of that investment came in the first three years of our
existence. And because of the unique construction methods re-
quired for offshore platforms, we spent a great deal of time and
money training a work force capable of producing the quality levels
that our clients expect.
Just during 1990, for example, because of the cyclical nature of
the business, we spent over $1 million training 200 unskilled work-
ers.
As noted earlier in Mr. Stewart's testimony, our industry has
lost 450,000 jobs in the past decade. If you just consider the Bull-
winkle project alone, it created an average of over 600 jobs for
three years, over a three-year period in south Texas, just for us.
Additional project procurements made in 33 of 50 States added a
considerable amount of economic impact to the United States.
When you take the expenditures of the indirect suppliers, we un-
doubtedly impacted the economy of almost every State in the
Union.
23
A predictable OCS development will produce jobs across the
United States, not just jobs for coastal States involved in offshore
development.
Deepwater development is not only good for reducing our de-
pendence on imported energy, it definitely, without a doubt, is a
job-creating and economically stimulating industry.
I might add, in the years I have been in this business, I have no-
ticed that our clients, the major oil companies and all the oil com-
panies have been ahead of their time in recognizing the environ-
mental needs in their development programs.
The petroleum industry can, through this H.R. 1282, as a start,
provide our Nation's domestic energy requirements. Producing this
domestic energy will strengthen our economy by generating new
jobs, allowing the return to work of those trained workers who lost
their jobs during the past decade, reducing the flow of dollars to
buy foreign energy, and creating additional revenues for the Feder-
al Treasury.
At the same time, it will help President Clinton meet his objec-
tives of increasing the use of natural gas for its environmental ben-
efits.
Thank you for hearing my testimony.
[The statement of Mr. Rodrigue can be found at the end of the
hearing.]
Mr. Ortiz. Thank you very much.
There is no question that we have had some very interesting tes-
timony from you, the witnesses of this panel. I have a question for
Mr. Flynn and Mr. Nesvold.
Approximately what percentage of your company's total explora-
tion and development budget goes to foreign projects? Will this leg-
islation help to bring some of this money back to the United
States? Maybe you can enlighten members of this Subcommittee.
Mr. Nesvold. In 1990, approximately 60 percent of Phillips'
budget was used on domestic projects. As of 1992, that had dropped
to about 40 percent, and basically it is the problem with running
out of prospects. Our money is going overseas.
Mr. Flynn. If you look at Exxon's worldwide spending on capital
and exploration, 1992 is about $7.4 billion. About a third of that
was spent in the U.S. If you go back about 10 years, it was about $9
billion and a little over half was spent in the U.S.
I think the kind of incentives we have talked about today, both
the royalty relief and the tax credit, would do a lot toward helping
us progress domestic developments in the deepwater Gulf of
Mexico.
Mr. Ortiz. Mr. Wilbourn, if you would like to give us some in-
sight.
Mr. Wilbourn. Mr. Chairman, within Texaco we are spending in
1993 and projected 1994 somewhere between 55 and 60 percent of
our E&P budgets overseas. The thing I think we should realize is
there is no shortage of opportunities when you look at what is on
our plate today. If you consider the fact that Russia is open, when
you consider what is available in China, consider other areas of the
world like West Africa and South America, we are not short on op-
portunities.
24
Mr. Ortiz. I have got another question, then I would like to yield
to Members of the Committee. This is for Mr. Flynn and Mr. Nes-
vold.
For your deep Arctic and deepwater exploration and develop-
ment projects, approximately what percentage of the contracting
work is completed by U.S. companies? Will the exploration and de-
velopment of any new deepwater areas be accomplished through
the use of U.S. companies?
Mr. Flynn. Yes, I think the pattern you heard earlier in the day
on projects and domestic spending is exactly right. A large amount
of the United States benefits, both directly and indirectly, through
service, labor and material contracts. And I don't see any change
in that as we move further into deepwater.
I think we want to continue to develop technology domestically.
It will help stimulate the economy, create jobs, and that is exactly
what we are here today to talk about.
Mr. Nesvold. Currently in the Arctic it is not as far along as the
deepwater. We don't have any major projects currently being devel-
oped. The closest thing would be some of the recent expansions at
Prudhoe Bay, which were done at New Iberia, Louisiana, and re-
sulted in a substantial increase in the local job market down there.
Mr. Wilbourn. The statement was made earlier that we are
losing our edge. I think we see that around the world, where the
technology for offshore development is coming from other places
other than the U.S., where it has come from in the past. So there is
opportunity here.
Mr. Ortiz. Because I am very concerned that if we provide these
incentives and then if we don't create jobs in the United States,
then we are going to have some problems. But you do feel there
will be jobs created? Great.
I would like to yield to my good friend, Mr. Green, for any ques-
tions he might have.
Mr. Green. Mr. Chairman, I am going to yield to Congressman
Laughlin.
Mr. Laughlin. Thank you. I have got people waiting in my office
on some of these very problems.
To follow up on the Chairman's first question, if you went back
10 years — and the gentleman, Mr. Flynn from Exxon, did that — but
if your other companies went back 10 years beyond his question,
your percentage of expenditure of dollars for whatever your explo-
ration activities would have been would have been even higher
here in the United States, I take it, domestically? You need to
answer with some oral response. I want it in the record.
Mr. Nesvold. Yes. I don't have that information right at hand,
but it has been steadily declining since 1990, anyway.
Mr. Wilbourn. Within Texaco over the last 10 years we have
done a 60/40 flip-flop. We have gone from 60 percent in the United
States, and 40 percent overseas, to just about the opposite in 10
years.
Mr. Laughlin. I think Mr. Rodrigue made a very valid point.
When you are spending that money domestically, that is circulat-
ing around a lot of different businesses. Is that your experience at
Exxon and Phillips and Texaco?
25
Mr. Flynn. That is very much our experience. I think the study
that was referenced by the earlier panel said if a $5 a barrel tax
credit by 1998 developed an additional 2 billion to 9 billion barrels,
it would create 56,000 to 105,000 jobs. That provides a lot of money
moving through the economy to stimulate it.
Mr. Laughlin. Mr. Rodrigue, in the big scheme of things, your
company, I take it, is in Aransas County, Aransas Pass?
You are on the wrong side of the county line. You have got
smart employees living in the 14th District.
The point you were making about having suppliers in 33 of the
50 States on that one project is a point I think many in the non-oil
States of our country lose site of the impact of exploration in oil
and gas. In the scheme of things, your company is small compared
to Texas or Exxon or Phillips or any of the other what we call
majors down there in south Texas, isn't that true?
Mr. Rodrigue. Yes, sir.
Mr. Laughlin. And here you are doing business in 33 of the 50
States. Now — you are nodding your head.
Mr. Rodrigue. The things we buy to build the offshore structures
come from 33 States. The personnel we use to man the projects
comes from the different States.
Mr. Laughlin. Some of those States in that 33 category are
States, I assume, that are not considered by most Americans or
people living in those States as oil and gas producing States; is that
correct?
Mr. Rodrigue. Yes, sir, that is correct.
Mr. Laughlin. Did any of them ever object to taking your
money?
Mr. Rodrigue. No, they want to know when we are going to pay
them.
Mr. Laughlin. Did any of them object to selling you products?
Mr. Rodrigue. No.
Mr. Laughlin. Even knowing it was going to the oil and gas in-
dustry down in south Texas?
Mr. Rodrigue. No, they tend to solicit our business quite heavily.
Mr. Laughlin. And the point I want to make there is, there are
many beneficiaries in all our States to the oil and gas industry;
isn't that to your experience, Mr. Rodrigue?
Mr. Rodrigue. Yes, sir.
Mr. Laughlin. In fact, when people think the oil and gas indus-
try just benefits Texas, Louisiana, and Arkansas, that is an incor-
rect assumption on their part, isn't that true?
Mr. Rodrigue. Yes, sir. I mean, Iowa had 21 vendors.
Mr. Laughlin. Iowa?
Mr. Rodrigue. Iowa, yes, sir.
Mr. Laughlin. And if my lifetime I have never heard anyone
suggest Iowa was an oil or gas producing State, have you?
Mr. Rodrigue. No, sir.
Mr. Laughlin. Have you ever heard anyone suggest that?
Mr. Rodrigue. No.
Mr. Laughlin. I haven't either. And that is the point that I
think is so often lost. And I very much appreciate your testimony.
That demonstrates even a State like Iowa that is not thought in
26
the minds of probably anyone in that whole State as being an oil
and gas producing State, they have benefited from this industry.
Would you agree with me that if we can get passage of this bill
for which the testimony has been offered today that it would bene-
fit people in non-oil and gas producing States?
Mr. Rodrigue. Yes, sir.
Mr. Laughlin. Even I believe the State of Maine or New Hamp-
shire has no oil wells in it. Would it benefit people in those two
States?
Mr. Rodrigue. In this example I have, Massachusetts had jobs,
Connecticut, New York, Pennsylvania, Delaware.
Mr. Laughlin. Pennsylvania is a producing State, as I recall it.
You are a small company and you have done business in these
traditional nonproducing States; correct?
Mr. Rodrigue. Yes, sir.
Mr. Laughlin. Would you, with your south Texas logic, figure
that these big companies like Texaco and Phillips and Exxon have
done some business with supply companies in these nonproducing
States?
Mr. Rodrigue. I would think so, yes.
Mr. Laughlin. I would, too.
Thank you, Mr. Rodrigue. Your testimony has been about as val-
uable as any we have had before this Committee in a long time.
Appreciate you coming up here representing your employees from
Aransas County in the 14th district.
Mr. Rodrigue. Thank you.
Mr. Laughlin. Mr. Nesvold, I wanted to ask you, you gave and
so have others given some testimony about drilling in the Arctic
Ocean, and we have had testimony about Russia, and we have had
people come by from time to time to talk about the vast oil re-
serves in the Siberian area and the areas of Alaska where the Rus-
sians have even had — I have had people tell me the Russians have
had our people come over there, and they don't have a lot of the
structures out in the Arctic region of Russia that we have in
Alaska. So I want to ask you particularly about Alaska, and
anyone else that is got operations there, I don't remember Exxon
being there, but if they are, can you nod?
Mr. Flynn. A partner but we do not operate.
Mr. Laughlin. Maybe you want to fill in, but are the restrictions
on the use of Alaskan North Slope wetlands inhibiting develop-
ment of the Arctic frontier areas?
Mr. Nesvold, if you will answer first, and anyone else operating
in that area.
Mr. Nesvold. We are very concerned about permitting pipelines
or drilling pads on the wetlands. Obviously two of our major goals
are to; (1) develop oil to reduce our dependence on foreign oil; (2)
with a minimum environmental impact. And the best place to do
that is where you have opportunities for large oil accumulations
with existing infrastructure. And we feel the North Slope of Alaska
and Beaufort Sea area is one of those areas, as are any operations
in the Gulf of Mexico.
Mr. Laughlin. When you are talking about the Beaufort Sea
area and Alaskan North Slope area, we have had before this Com-
mittee some controversy about ANWR. Are you talking about
27
going up in the mountains and the meadows of the ANWR area to
do this drilling that you are talking about?
Mr. Nesvold. No, sir. All of our drilling that we have been talk-
ing about so far is offshore.
Mr. Laughlin. Out in the water?
Mr. Nesvold. In the Beaufort Sea. It is not on-shore in the
ANWR area.
Mr. Laughlin. The reason I ask that, most of the time when
people come in to see me about drilling up there, they want to sug-
gest the drilling is going to be into the interior, some 20, 30, 50
miles interior from the Arctic Ocean and ANWR up in the moun-
tains and the meadowlands. I just wanted to get focused where you
are talking about the prospective drilling you are testifying to
about today.
Mr. Nesvold. No, we are talking about offshore North Slope de-
velopments.
Mr. Laughlin. People come into my office and represent that
Phillips is wanting to do this type of drilling up in the ANWR
mountain lands, if they would be misrepresenting your drilling
plans at this time; is that
Mr. Nesvold. The technology I am testifying on is in regards to
offshore drilling.
Mr. Laughlin. Mr. Flynn, do you have any
Mr. Flynn. No, I really don't have anything else to offer.
Mr. Laughlin. What happens if the Transalaskan Pipeline
System becomes uneconomic to operate and is abandoned before
you get an opportunity to bring the Arctic fields into development?
Mr. Nesvold. It is similar to the response on use of the wetlands.
We have to make use of existing infrastructure where it exists next
to major reserve potential areas. And probably another good exam-
ple of the importance of the TAPS line is the McKenzie River delta
area over in the Canadian area of the Beaufort Sea which has not
been developed, although there have been fields discovered with as
high as 300 million barrels in place. But due to lack of infrastruc-
ture, it has been uneconomical for Canadians to develop those
fields.
Mr. Laughlin. H.R. 1282 proposes various incentives for both
deepwater and frontier exploration, which, if either one of those or
any of these incentives, would benefit Phillips Petroleum?
Mr. Nesvold. We only have very small position in water depth,
greater than 200 meters. Our primary interest right now is in
Arctic explorations. But we would be very interested in broad-
based royalty incentives that would provide incentives to develop
marginally economic fields.
Mr. Laughlin. That is all the questions I have. Thank you very
much, Mr. Chairman.
Mr. Ortiz. Thank you.
Mr. Green?
Mr. Laughlin. Oh, you know, I did have one other short ques-
tion. Who is it that is now challenging us for the lead in offshore
oil technology?
Mr. Juvkam-Wold. Primarily the countries around the North
Sea, to some extent also the Brazilians. From the North Sea we are
talking about England, Scotland, Norway. France to some extent.
28
Mr. Laughlin. What is happening to allow them to overtake us?
And I guess you could make the comparison to the Japanese over-
taking us in the automobile industry. What is allowing these coun-
tries of Scotland and England and Norway and Brazil to overtake
us in offshore technology?
Mr. Juvkam-Wold. Probably the main factor is more funds allot-
ted to R&D. But they have also specific projects that require this
new technology and they develop the technology as they need it.
And we in the U.S. have been able to supply the technology needs
in the world for oil and gas development for many decades, but
since we are not developing very much new technology here at this
time, they are leapfrogging ahead of us in certain specific areas.
For instance, Brazil has the deepest subsea well completions.
And you mentioned Japan. It is my understanding that Japan is
currently designing a drill ship to drill in deeper waters than any
that we currently have in the U.S. That won't happen for many
years, but they are moving into this area also.
So unless we promote R&D in the U.S. to a greater extent and
more long-term, I think we are going to be slipping further behind.
Mr. Laughlin. Thank you very much.
Thank you, Mr. Chairman.
Thank you, Mr. Green.
Mr. Ortiz. Mr. Green.
Mr. Green. Thank you, Congressman Laughlin.
Congressman Laughlin's question about the offshore and
ANWR — I know that is not what we are here for — there is current
production or exploration and hopefully production offshore of
ANWR; is that not true?
Mr. Nesvold. There is exploration in the Camden Bay area, but
there is no production offshore ANWR.
Mr. Green. What is standing in the way? I understood the
ANWR was mainly on-shore issues.
Mr. Nesvold. Yes, it is. It is totally on-shore. That is why my tes-
timony did not address ANWR whatsoever.
Mr. Green. That is why I was wondering. I have had those same
folks in our office and we have never talked about offshore, be-
cause I thought that was available now and we could do develop-
ment and exploration and also actual production.
Mr. Nesvold. Yes. If it was economic, if someone had a large
enough find, yes.
Mr. Green. But it is not because of government regulations or
ANWR or anything else. It is the market that is doing that to us?
Mr. Nesvold. Yes.
Mr. Green. On another side note that Congressman Laughlin
brought up — and I know we benefit particularly in Houston, the
Offshore Technology Conference every year, it has been a great
thing for Houston, I think for Texas, and for the Nation— in the
testimony about the development of technology in other parts of
the world, particularly the North Sea, will this piece of legislation
help us to encourage that particular technology in deep sea explo-
ration?
Mr. Juvkam-Wold. I believe so, yes.
Mr. Green. The question I asked of the first panel, the one con-
cerning the 175 oil and gas discoveries, our Chairman mentioned in
29
his opening remarks, I asked about it again, that was mainly eco-
nomics or market. And again I recognize what is happening with
the price per barrel as we sit here today. Is that the basic reason
why we have only explored or dealt with 23 of those 175 discover-
ies? And that is for anybody on the panel.
Mr. Flynn. I think the answer they gave earlier is probably ac-
curate. I don't have detailed knowledge of those particular ones. I
will tell you that the slope has unique geologic and economic risk.
It is contained in the written and oral testimony that I provided.
And the kind of incentives you are talking about today coupled
with the tax incentives really hold the promise to help us further
develop those areas.
Mr. Green. Let me ask Exxon about the Zinc Project as one of
those 23 that were chosen. When will it begin? And if you can ex-
pound on it and talk about the estimated cost and the number of
jobs we are talk about it may create.
Mr. Flynn. The combined Zinc- Alabaster development cost about
half a billion dollars. The Zinc subsea development started up just
this last month, and it is currently producing, although we are still
completing the drilling operation there. So it is on line, as is the
Alabaster host platform.
I don't have with me the detailed breakdown of jobs. We haven t
done the analysis that way. I will be glad to look into that and see
if we can provide it to your staff.
Mr. Green. I appreciate that. The only time I have been to an
offshore platform is actually in Alaska in the Cook Inlet. It is
almost like the Committee here today, that everybody on the plat-
form spoke like I did. They either pronounced Rodrigue from Lou-
isiana or they had a slow drawl like Congressman Laughlin and I
from Texas. So I would be interested to see the impact it would
have, particularly in the Gulf Coast area.
Thank you, Mr. Chairman.
I thank the panel. It has been a good panel.
Mr. Ortiz. Thank you.
I have just one more question. Mr. Rodrigue, I know you built
the Bullwinkle. Do you have the technology and expertise — and I
believe that you do but 1 would like to hear it from you for the
record — to fabricate the facilities for any deepwater finds in the
gulf? And how about the Arctic? Do you believe that the United
States is losing the technology in the oil and gas field in that area?
Mr. Rodrigue. Well, for the gulf, we have the capability to build
just about anything that the gulf needs. We have prequalified on
some unique and deepwater projects, TLPs, for example. We have
prequalified to fabricate hulls, the top sides, the tendons, the foun-
dations of them.
In the Arctic side, we are actually doing some studies and look-
ing at some concepts for concrete structures for some of the finds.
They are the real early conceptual designs, but we believe we can
do concrete technology that will make some of these Arctic struc-
tures viable.
There is a concrete structure being built for the eastern coast of
Canada called Hibernia. Our company along with a joint venture
partner from Norway who has a lot of concrete technology, bid un-
successfully on the Hibernia project.
74-587 0-93-2
30
We just received a $125 million project through our parent com-
pany to outfit some of the work in Canada. But we would hope we
could furnish the expertise for the Arctic from the United States
with this new concrete technology, possibly.
Mr. Ortiz. Very good. I thought that was the last question, but I
have one more question for Dr. Juvkam-Wold.
Does this production require any additional environmental safe-
guards? If so, what are the offshore operators doing to implement
these safeguards? Has there been any research completed to ad-
dress these issues, Doctor?
Mr. Juvkam-Wold. There is ongoing research in the safety of
drilling offshore. Several universities have programs going on in
this area, both from a well-control and a blowout prevention point
of view and also from a training point of view. And there are some
more complicated problems that we have to deal with as we get
into deeper waters. I think we do know how to handle these things,
but we need to become more conversant with those technologies.
Mr. Rodrigue. One comment I would like to elaborate on, talk-
ing about the environmental aspect of it, Mr. Fry in his earlier tes-
timony this afternoon mentioned that developing the Gulf of
Mexico decreases your reliance on transporting crude by tanker.
And I think the offshore oil and gas industries, there is a big mis-
conception in the public's eye about offshore oil and gas versus oil
transported on tankers.
Mr. Ortiz. If I am correct, I think most of the spillage has been
not because of the drilling but the transportation. Am I correct?
Mr. Rodrigue. Yes. There is more oil in the oceans from natural
seepage than there is from offshore production. I think there are
statistics that prove that out.
Mr. Ortiz. Very good. Mr. Green, do you have any other ques-
tions?
Mr. Green. No other questions, Mr. Chairman. I appreciate the
testimony. I think it was good. Thank you.
Mr. Ortiz. I think that this concludes the testimony, unless
somebody else would like to add anything else that maybe has been
left out.
If not, I really want to thank you for your testimony and the in-
sights you have shared with us today. I think we have heard very
interesting testimony this afternoon.
I know there are some other members who cannot attend this
hearing this afternoon because they had other obligations. And
some of them will be submitting to the panel some questions that
we hope you will be able to respond to.
[The information can be found at the end of the hearing.]
Mr. Ortiz. If there is nothing else, the hearing stands adjourned.
Thank you.
[Whereupon, at 4:25 p.m., the Subcommittee was adjourned, and
the following was submitted for the record:]
31
Testimony of
Tom Fry
Director, Minerals Management Service
Department of the Interior
Before the
Committee on Merchant Marine and Fisheries
Subcommittee on Oceanography, Gulf of Mexico,
and the Outer Continental Shelf
U.S. House of Representatives
Washington, D.C.
September 14, 1993
Mr. Chairman and Members of the Committee, I appreciate the opportunity
to appear before you today to testify on H.R. 1282, "The Outer Continental
Shelf Enhanced Exploration and Deepwater Incentives Act."
Let me preface my comments by saying that the Administration is currently
reviewing its OCS policies, including coordinating with the Department of
Energy's Domestic Gas and Oil Initiative and here at the Department of the
Interior through the Secretary's OCS Advisory Board. Once the review is
complete, we will be in a better position to provide more specific comments
on OCS issues.
This bill would clarify the discretionary authority given to the Secretary of
the Interior under the Outer Continental Shelf Lands Act (OCSLA) to
reduce or suspend royalties on existing leases. Second, the legislation adds a
new provision to the Act mandating the Secretary to suspend royalties on all
new production in water depths greater than 200 meters until capital costs
are recovered. Third, Section 18 of the OCSLA would be amended to
require the Secretary, when developing an OCS 5 Year Program, to
designate as "frontier areas" portions of the OCS, if any, where royalties will
be reduced or suspended and the terms of such reduction or suspension.
The Minerals Management Service (MMS) supports the bill's objectives of
environmentally sound natural gas and oil investment, production, and
32
employment on the Outer Continental Shelf (OCS). The deepwater
portions of these areas represent some of the most promising exploration
targets in the United States, but the economic and technological challenges
industry confronts in deepwater are substantial and some incentive may be
necessary to encourage development
The MMS has reviewed the bill's provisions with an eye toward striking a
balance between ensuring the public a fair return on the value of its OCS
resources and providing industry with appropriate financial incentives. To
the extent possible, a bill should target benefits projects to that would not
be undertaken in the absence of the incentives.
The proposed language in Section 8(a)(3)(A) would clarify the Secretary's
authority to grant royalty rate reductions on both producing and non-
producing leases in order to "promote development" and "encourage
production of marginal...resources." The existing royalty rate reduction
authority traditionally has been interpreted to limit the Secretary to
considering reductions only on leases that are already in production. The
change clarifies the Secretary's authority to design a royalty rate reduction
policy on existing leases that could increase the overall economic benefits of
development to the Nation.
The Solicitor's office within the Department has advised the MMS that it
has the issue of the extent of existing authority to grant royalty rate
reductions on non-producing leases under serious study. The Solicitor's
office believes that the Secretary might have legal authority to promulgate
regulations allowing him (or the MMS) to grant royalty reductions to non-
producing leases on a case-by-case basis under certain specified
circumstances (or if certain conditions are met) that show that the purposes
of the OCSLA would be served. The Solicitor's office emphasizes that this
authority can only be implemented through rulemaking, requiring us to
publish a proposal and receive and consider public comments on it.
Section 8(a)(3)(B) of the proposed bill mandates that royalties be suspended
on leases in water depths of 200 meters or greater until capital costs are
recovered. This section has been analyzed in detail because it could have a
significant effect on the economics of production in these water depths. It is
helpful to consider separately the effect of this section on existing leases and
on new leases to be issued in future lease sales.
33
To estimate the effect on existing leases, the MMS has analyzed 30
discoveries that are large enough to merit consideration for development on
non-producing leases in water depths greater than 200 meters in the Central
and Western GOM. The MMS results indicate that this proposal would
affect the decision on whether to produce on only two of these fields, both
located in water depths of greater than 400 meters. These two fields
contain an estimated 150 million barrels of oil equivalent.
However, the estimated revenue gains from bringing those two fields into
production would be more than offset by royalties forgone from the other
fields that would have been produced even in the absence of the incentive.
This is estimated to be a net loss of $1.9 billion (in 1993 dollars) in royalty
collections. It should be noted that no royalties are expected to be forgone
until sometime after 1995, and the total net loss will be spread over the life
of the fields. Further, these estimates reflect possible changes in royalty
collections only, and these losses should be partially offset by increased tax
collections.
For new leases, a mandatory suspension provision could provide benefits to
lessees that should lead to increased bonuses for new leases in these water
depths, because bidders will bid on more tracts and bid higher amounts
when royalty burdens are reduced. MMS estimates that an additional $3-5
million per year in bonuses will be collected from Gulf of Mexico lease sales
if this bill is enacted.
In summary, the mandatory royalty suspension provision, as currently
written, can be expected to increase bonus revenues to some extent.
However, these expected gains would be more than offset by an estimated
decrease in royalty collections over the long term. It should be noted that
the overall, long-term budgetary impacts are speculative because of
uncertainties regarding the amount and timing of development of unleased
resources.
As stated previously, we support the objective of the bill, but have not
reached a decision regarding the specifics of the legislation. We offer the
following as types of changes that, if made, would make it more likely that
the Administration could support the royalty suspension provisions of the
bill.
34
• The mandatory suspension should be applied to new leases only. This
allows new leases to be issued with more attractive lease terms in deep
water to promote activity that can provide substantial economic
benefits, stimulate the development of new technology, and provide
important natural gas and oil resources for the Nation. However, it
also allows the public to benefit from greater bonus receipts in future
deepwater lease sales, while avoiding the losses associated with royalty
reductions on existing leases that might be produced at current royalty
rates.
• The suspension provision should be limited to tracts in 400 meters of
water or greater. The analysis mentioned above did not identify any
discoveries on existing leases in the 200-400 meter range that would be
made profitable by the proposal, and MMS does not expect that
offering a royalty suspension on new leases in these water depths will
stimulate much additional leasing or development Furthermore,
conventional fixed platforms can be used in water depths out to 400
meters. In deeper waters, new and innovative technologies are
required to produce the gas and oil, and an incentive that targets
these depths may help develop those technologies.
• Capital costs should be defined to allow the Secretary to set a
schedule of allowable costs in regulation, rather than use actual costs.
This would greatly simplify the administrative burdens for both MMS
and industry and avoid the problem of a larger benefit being given to
less efficient (higher-cost) operators.
• The mandatory suspension provision should be limited to tracts in the
Central and Western Gulf of Mexico. Most areas outside of these
areas are currently under moratoria. The Department believes it
should resolve issues concerning new leasing and development in these
other areas before providing additional incentives to develop them.
Likewise, the designation of "frontier areas" should be limited to areas
of the Central and Western Gulf of Mexico until larger policy issues
are resolved
Finally, with regard to proposed changes to Section 18 of the OCSLA, I
would note that the Act authorizes the Secretary to propose any system of
bid variables, terms and conditions-potentially including a royalty
suspension system-that he determines to be useful to accomplish the
35
purposes of the Act when offering leases for sale. Any such system can be
implemented if Congress does not disapprove the proposal within 30 days.
Thus, current authority appears to carry out the intent of the proposed
change to Section 18 and would be more efficient to implement than the
proposed language. Under the proposed language of H.R. 1282, the
Secretary would have to define what qualifies as a "frontier area," and a full
description of the terms of the incentives must be announced as part of an
OCS 5 Year Program. These provisions could restrict the Secretary's
flexibility to respond to changing economic conditions because both "frontier
areas" and incentive terms would be set perhaps years before they would be
used and could not be changed without undergoing a lengthy and
cumbersome review, as required by Section 18.
You also requested that I address the various legislative proposals that
would offer tax relief for OCS production. Tax law is outside the
Department of the Interior's realm of expertise, so MMS analysis may not
be adequate for the Subcommittee's purposes. In general, tax credits can
provide a more powerful incentive than can royalty suspensions or
reductions. Thus, if set at high enough levels, tax credits can both increase
the benefits to lessees and increase the costs-relative to royalty relief~of
providing incentives for deepwater production.
We would recommend that any legislative proposals offering tax relief for
OCS production be consistent with the principles previously discussed with
respect to H.R. 1282:
•
The incentives should result in increased production of natural gas
and oil from the OCS;
• The tax relief should apply only to projects that would not be
undertaken in the absence of the incentives; and
• The public should receive a fair return on the value of its OCS
resources.
Mr. Chairman, this concludes my prepared testimony. I will be pleased to
respond to any questions that the Subcommittee may have.
36
TAKE""
how in!
United States Department of the Interior amrkV
MINERALS MANAGEMENT SERVICE
WASHINGTON. DC 20240
NOV 29 ■&
Honorable Gerry Studds
Chairman, Committee on Merchant Marine
and Fisheries
House of Representatives
Washington, D.C. 20515
Dear Mr. Chairman:
I am pleased to enclose responses to questions submitted by the
Committee as a follow-up to the September 14, 1993, Hearing on
H.R. 1282, the "Outer Continental Shelf Enhanced Exploration
and Deep Water Incentives Act."
Thank you for the opportunity to provide this material to the
Committee. If you have any further questions or need additional
information, please let us know.
Sincerel
Director
Enclosure
Honorable Jack Fields
Honorable Solomon Ortiz
Honorable Curt Weldon
37
1) How do the short-term revenue losses from royalty relief
compare with the potential overall increases to OCS revenues from
expanded offshore production and overall benefits in terms of
domestic economic grovth and job creation?
According to the MMS analysis, H.R. 1282 may possibly
generate additional revenues ($3-5 million per year) in the
early years due to increased bonus bids on the sale of
currently unleased deepwater acreage in upcoming Central and
Western Gulf of Mexico OCS lease sales under the royalty
suspension terms found in H.R. 1282. This revenue gain is
estimated to offset the small reduction in royalties in
existing leases over the next several years, since the
majority of discoveries in deepwater are not expected to
come on line until after 1996.
The MMS analysis of 30 fields large enough to merit
consideration for development and located in water depths
greater than 200 meters strongly suggests that, over the
long term, an across-the-board royalty holiday would provide
benefits to about 16 fields that would be developed without
the relief. Thus, for these deepwater prospects, there is
not necessarily a tradeoff between revenue losses and
expanded offshore production with associated economic growth
and job creation since much of the job creation is expected
to occur anyway.
38
2) Has any decision been made on tbe revised definition of deep
water for tbe purpose of reducing 0C8 royalty rates? should
bonding requirements be bigber for deep vater or frontier
area drilling rigs or production facilities?
a. No decision has been made at this time to revise the
definition of "deep water" for the purpose of reducing OCS
royalty rates.
b. Higher bonding requirements may be utilized in situations
where it is evident that lease abandonment costs will be
substantial. One example of this situation is exploration
and production in deep water or in certain frontier areas
where infrastructure requirements are greater than normal.
Depending on the particular circumstances, higher
requirements are established on a lease-specific basis under
the supplemental bonding provisions of the governing
regulations.
39
3) Does deep water or frontier area drilling and production pose
any new environmental risks? Does this legislation impact any
existing environmental protections, laws, regulations, permits,
etc?
a. In general, development and production activities in deep
water do not pose any new environmental risks. Instead,
development and production activities in these areas could
pose impacts to environmental resources not encountered
elsewhere. For example, chemosynthetic communities have
been located in portions of the deepwater Gulf of Mexico (in
water depths greater than 400 meters) . Chemosynthetic
organisms, mainly bacteria, use chemical processes, rather
than light, for energy. Platform or pipeline placement and
anchoring of support vessels or floating drilling units
could potentially impact these communities.
However, a Notice to Lessees requires operators to use
geophysical records and photo documentation to identify and
protect chemosynthetic communities. Because of this
protective measure and the fact that chemosynthetic
communities are widespread, any impacts which might occur
are expected to be limited, and areas are expected to
repopulate quickly. A large number of the several hundred
leases in deep water in the Central and Western Gulf of
Mexico have been developed without any significant impact to
the existing environment.
Frontier area drilling and production could possibly pose
some new environmental risks. Risks would be associated
with operating in environments that are less familiar and
harsher, in some respects, than the established producing
areas.
Certain frontier areas also may have environmental resources
not encountered elsewhere, such as the endangered bowhead
whale offshore Alaska. The bowhead whale, as well as other
sensitive environmental resources, have been studied
intensively to eliminate or minimize the effects of drilling
and production in frontier areas. Also, various
stipulations have been recor.jenJeJ for leases issued in
Alaska and other frontier areas to help mitigate any
expected impacts to environmental resources located in a
particular area.
b. The proposed bill, H.R. 12 82, does not appear to impact
existing environmental protections, laws, regulations,
permits, etc.
40
4) Would the language in Section 8(a)(3)(A), which clarifies the
Secretary's authority to grant royalty relief, be helpful in
reducing royalty rates on existing leases?
The traditional interpretation of the existing royalty rate
reduction authority limits the Secretary to considering only
leases that are already in production. The Department's
Solicitor's office is studying whether authority exists,
through rulemaking, to reduce royalty on non-producing
leases. Language in section 8(a)(3)(A) clarifies that
authority .
41
5) what are the cost estimates to the Federal Government for
providing various incentives? What impact will these incentives
have on the federal budget deficit?
As we stated in our testimony, tax law is outside the
Department of the Interior's realm of expertise.
42
*1) If your suggestions to allow royalty relief only on new
leases and only in water deeper than 400 meters were followed,
how would this change your budgetary impacts analysis of H.R.
1282?
If H.R. 1282 were applicable to both active and new leases
located in water depths greater than 400 meters, we estimate
that the total loss of royalty revenues over the life of the
projects would be reduced by approximately 15 percent (from
$1.9 billion to $1.6 billion). However, if H.R. 1282 was
applicable to new leases only, no significant budget impacts
are expected.
43
•2) Why does the Department not feel that the increased costs of
Arctic development merit royalty relief?
Currently, Arctic leases are subject to the same lease terms
as deep water leases (water depths of 400 meters or more) in
the Gulf of Mexico, i.e., longer lease terms and the lower,
one-eighth royalty rate.
To date, industry discussions of incentives (such as royalty
suspension) have focused on the deep water Gulf of Mexico,
so we are looking more closely at that area at this time.
In the future, we may also consider whether any such
incentives are appropriate in the Arctic. However, the
Department has taken no position on incentives for Arctic
areas at this time.
44
*3) If the Secretary of Interior already has the authority to
reduce or suspend royalty payments, why has the authority only
been used a few times?
Traditionally, and for some understandable, practical
reasons, the Secretary's royalty reduction authority has
been interpreted to apply only to leases already in
production. Since 1980 (when the first application for
royalty relief was received) , only 8 applications have
requested royalty relief. Of those 8 applications received,
4 were approved; 3 were denied; and 1 is under review.
It also should be noted that drawing the line between when
to grant or when to deny royalty relief requests, as well as
deciding how much royalty relief to grant, is a complex
process. Section 8(a)(3) of the OCS Lands Act allows the
Secretary to reduce or eliminate royalty to "promote
increased production." However, royalty reduction, in
essence, involves changing the terms of a lease, and lease
terms can only be changed after compiling a record which
clearly sets forth the reasons for granting or denying that
change of terms. This process takes time, a rational
analysis, and a basis for that action.
45
*4) How are current deepwater lease holders going to react to a
royalty suspension only on new leases? What can ve do to
encourage production on deepwater leases that at this point are
only marginally economic?
a. The response to your first question is speculative, at
best. Some current lease holders may react by developing
tracts that are profitable under existing royalty rates.
Some lessees may expeditiously relinquish tracts that are
not profitable under current royalty rates, allowing tne
Government to reoffer the tracts potentially at more
favorable terms to bidders. Finally, should the Department
determine that it has the authority for royalty relief on
non-producing leases under current law, or should Congress
enact legislation clarifying such authority, lessees holding
marginally valued tracts may submit requests for royalty
reief on a case-specific basis.
b. Production on deepwater leases which are marginally
economic can be encouraged through new legislation that
clarifies the authority of the Secretary to provide royalty
relief on a case-by-case basis for non-producing leases.
46
*5) Will the Domestic Gas and Oil Initiative look at incentives
such as this bill as vsll as tax incentives?
We defer to the Department of Energy for a response to this
question.
47
*6. Do I hear the Administration witnesses leaning toward natural
gas production incentives? Are we starting to separata oil and
gas production issues?
Given new requirements in the Clean Air Act Amendments and
concern over the impact of emissions on global climate
change, a steady and secure supply of clean-burning natural
gas is expected to be of increasing importance to the
Nation. The Administration is reviewing a wide variety of
alternative policies for the OCS program. Although we
intend to emphasize production in gas-prone areas of the OCS
and to publicize the benefits of natural gas, no definitive
decisions have been made at this time on either of your
questions.
48
*7) Why has the Administration urged that this type of
initiative be only applied to the Central and Western Gulf of
Mexico? Aren't there promising areas other than the Gulf where
incentives might make sense (such as the Arctic Ocean)?
Industry discussions of incentives have focused on the deep
water Gulf of Mexico, so we are looking more closely at that
area. Also, most areas outside of the Central and Western
Gulf are currently under moratoria. The Department believes
it should first resolve issues concerning new leasing and
development in these other areas before endorsing measures
to provide additional incentives to develop them.
In the future, the Department may also consider whether any
such incentives are appropriate in other areas, such as the
Arctic. Should the Secretary so decide, he has the
authority under section 8(a)(1)(H) of the OCS Lands Act to
propose any system of bid variables, terms and conditions
that he determines to be useful to accomplish the purposes
of the Act (including royalty reduction). Any such proposal
can be implemented if Congress does not disapprove the
proposal within 30 days and after appropriate regulatory
changes are promulgated.
49
*8) Has the tax legislation been scored and if so, how expensive
is it estimated to be?
To the best of our knowledge, none of the tax incentive
legislation has been scored.
50
*9) How do you justify your budget loss projections with
the results of a recent DRX/McGraw Sill study which projects
gains to the U.8. Treasury?
The DRI study, conducted for the oil and gas industry,
explicitly assumes that a $5 per barrel tax credit, applied
to production in water depths beyond 400 meters, would lead
to the recovery of all currently discovered deepwater
resources of 2 billion barrels of oil equivalents (BOE) ,
plus 7 billion additional undiscovered boe, all of "which
would not otherwise be developed." No support for this
assumption is provided. The DRI study also measures
secondary (multiplier) effects, which presumably would also
emerge under any one of a wide variety of policies
associated with providing $45 billion in tax credits to
selected private companies.
Although the MMS analysis is limited to discovered deepwater
resources, it attempts to identify which fields would and
would not be developed under tax credits provided by S. 403
and the royalty relief offered by S. 318 and H.R. 1282.
Further, the MMS analysis does not count secondary effects.
The MMS analysis estimates that over 1 billion BOE of
discovered deepwater resources are currently profitable, and
hence worth producing, without any tax credits. We project
that the remaining discovered deepwater BOE either will not
be profitable to produce even with the tax credits, or will
be produced despite having real costs greater than gross
revenues. We believe the same arguments would tend to apply
to undiscovered deepwater resources as well.
51
STATEMENT OF
JOHN A. RIGGS
PRINCIPAL DEPUTY ASSISTANT SECRETARY OF ENERGY
OFFICE OF POLICY, PLANNING AND PROGRAM EVALUATION
BEFORE THE
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF MEXICO, AND
THE OUTER CONTINENTAL SHELF
COMMITTEE ON MERCHANT MARINE AND FISHERIES
U. S. HOUSE OF REPRESENTATIVES
SEPTEMBER 14, 1993
52
Statement of John A. Riggs
Principal Deputy Assistant Secretary of Energy
Policy, Planning and Program Evaluation
before the
House Committee on Merchant Marine and Fisheries
Subcommittee on Oceanography, Gulf of Mexico,
and the Outer Continental Shelf
Good afternoon, Mr. Chairman and members of the Committee. My name
is John Riggs, and I am the Principal Deputy Assistant Secretary
for Policy, Planning and Program Evaluation at the Department of
Energy. It is a pleasure to appear before you to discuss United
States policy regarding oil and gas development on the Outer
Continental Shelf and to present the Department's views on H.R.
1282, the "Outer Continental Shelf Enhanced Exploration and Deep
Water Incentives Act."
The Administration is currently reviewing its OCS policies as part
of our Domestic Gas and Oil Initiative and at the Department of the
Interior through the Secretary's OCS Advisory Board. Once these
reviews are complete we will be in a better position to provide
more specific comments on H.R. 1282 and other OCS issues.
H.R. 1282
H.R. 1282 attempts to encourage the production of domestic oil and
53
natural gas resources in deep water on the Outer Continental Shelf
by offering royalty relief for new production. It would amend the
"Outer Continental Shelf Lands Act" such that any royalty or net
profit share set forth in any lease may be reduced or suspended
and would require a royalty suspension for new production from any
lease located in water depths of 200 meters or greater until the
capital costs directly related to such new production have been
recovered by the lessee. If, however, the price of oil rises to
$28 per barrel or the price of natural gas rises to $3.50 per MMBTU
the original lease-stipulated rate would apply.
ROYALTY REDUCTION
I want to discuss three situations regarding royalty suspension or
reduction for the deepwater OCS that are also addressed in H.R.
1282: areas that have never been leased or new leases, existing
leases that have not gone into production, and existing leases in
production.
Hew Leases: We agree with the Department of the Interior that a
royalty suspension on new leases for the early years of the lease
until capital costs are recovered could have a significant effect
on the economics of production at these water depths. It should be
noted, however, that it is uncertain if it would resolve the issue
entirely due to uncertainties concerning the amount of proven
reserves in deep waters. In addition to increased domestic
54
production, the benefits extend to increased high-wage, high-
technology jobs, as well as the development of new, advanced
technologies that will maintain the Nation's leadership in offshore
technology. These benefits ripple through our economy increasing
economic activity, leading to more jobs and revenues.
Ixisting leases: Existing leases fall into two categories, those
that have not begun production and those already in production.
Pre-production leases: Interior indicates that its Solicitor's
office is studying whether Interior can exercise its current
discretionary authority to grant royalty reductions to non-
producing leases on a case-by-case basis if the royalty reduction
can be justified. This approach may satisfy the goal of H.R. 1282-
-increasing the incentives for deepwater development — without
undermining the revenues that could be collected from leases that
would have gone into production without any royalty relief. There
also may be alternatives to this case-by-case approach that can be
explored to determine whether the benefits outweigh the costs
associated with royalty relief.
Producing leases : Interior already has the discretionary
authority to suspend royalties on a case-by-case basis for those
leases that are producing and are not economic. We agree with
Interior that no new authority is necessary to accomplish the goal
of maintaining production from presently producing properties.
55
The "Outer Continental Shelf Enhanced Exploration and Deep Water
Incentives Act" is a good example of the type of action we are
examining with a view to enhancing the viability of our domestic
oil and gas industry and increasing domestic production.
DOMESTIC GAS AMD OIL INDUSTRY
The U.S. gas and oil industry represents about $300 billion of our
Gross Domestic Product or about 5.5 percent of GDP. Just the
extraction portion of the industry employs about 380,000 people,
while the total industry employs about 1.4 million people. These
' are high paying, often high-technology, jobs that contribute to the
U.S. economy.
Development Cost*
Industry exploration and development costs are much higher on the
OCS than on land, and they increase significantly with water depth.
According to the Joint Association Survey, the cost for the average
exploratory onshore oil well is $64 per foot, whereas the cost of
the average exploratory offshore oil well is over 6 times that at
$392 per foot. In 1991, total costs for the average exploratory
natural gas well in the lower 48 states were almost $600,000
onshore and over $5 million offshore. In deep water, a tension
leg platform in 3000 feet of water can cost a billion dollars.
56
Increasing Production
At the same time/ we know that some of the OCS areas —
particularly the deepwater Gulf in excess of 400 meters — are
among the most promising. Increasing oil and gas production here
in the United States, in an environmentally sound manner, not only
increases jobs in oil and gas and their support industries, it also
reduces risks of foreign losses and enhances the efficiency of the
economy by encouraging technological breakthroughs, reducing oil
and gas transportation costs.
Technological Advancement
Doing the technically challenging projects also means assembling
cutting-edge scientific talent in oil and gas companies. Because
each oil and gas reservoir is different, because each area of
exploration is unique, some operations require a new technique.
Deep water drilling allows us to push beyond current producing
areas to those places that demand innovative thinking and new
solutions. It requires creative minds. The breakthroughs brought
on by this demand will benefit our future oil and gas industry. It
will also contribute to the retention of the relative advantage we
in the United States have in high-tech exploration expertise and
spread the use of the best environmental standards to the rest of
the world.
57
CONCLUSION
In conclusion , I would like to thank you again, Mr. Chairman and
members of the Committee, for the opportunity to present the
Department's views. With an estimated 28 percent of our domestic
proven and undiscovered recoverable natural gas reserves, the Outer
Continental Shelf is clearly a national asset of great importance
for our economy. We support the kind of careful management of our
national lands and waters that will offer the greatest benefit to
Americans of this generation and the next. It is clearly a tough
challenge .
Together, we need to find the best strategy for managing our
federal assets — such as the Outer Continental Shelf — and the
best mechanisms for keeping a strong oil and gas industry in this
country. Under the Domestic Gas and Oil Initiative and the
Department of the Interior Secretary's OCS Advisory Board we are
examining the relative merits of numerous actions, programs and
processes that will best govern that nationally owned wealth and —
at the same time — give us the most efficient and valuable energy
sector in the world. The Department looks forward to working with
the Committee on these issues.
58
DEPARTMENT OF ENERGY
Washington, DC 20585
November 15, 1993
The Honorable Solomon P. Ortiz
Chairman
Subcommittee on Oceanography, Gulf of Mexico,
and the Outer Continental Shelf
Committee on Merchant Marine and Fisheries
U.S. House of Representatives
Washington, DC 20515
Dear Mr. Chairman:
On September 14, 1993, John A. Riggs, Principal Deputy Assistant
Secretary for Policy, Planning and Program Evaluation, testified
before the Subcommittee on Oceanography, Gulf of Mexico, and the
Outer Continental Shelf regarding the Outer Continental Shelf
Enhanced Exploration and Deep Water Incentives Act (H.R. 1282).
Enclosed are the Department of Energy's answers to the questions
submitted by you and Congressman Fields.
If we can be of further assistance, please have your staff
contact our Congressional Hearing Coordinator, Lillian Owen, on
(202) 586-2031.
Sincerely,
illiam J. Taylor, III
Assistant Secretary
Congressional, Intergovernmental
and International Affairs
Enclosures
V
59
QUESTIONS FROM REPRESENTATIVE ORTIZ
Domestic Gas and Oil Initiative
Question 1: How does the proposed legislation fit into DOE's
National Energy Initiative? Are there other ways
to stimulate domestic offshore oil and gas
exploration, development, and production?
Answer: The Department of Energy is looking at a range of options
to increase oil and gas production. H.R. 1282 — the
"Outer Continental Shelf Enhanced Exploration and Deep
Water Incentives Act" — is similar to options which are
being considered. The Administration is examining costs
and benefits of various ways to more productively manage
nationally-owned assets as well as to stimulate domestic
oil and gas exploration, development, and production.
Among the options are: plans for cooperative
consideration within the Administration of production
issues; actions to encourage natural gas regulatory
reform; and examination of other limited changes in the
tax code.
Incentives such as lower royalties will be considered for
the deep water portions of the western and central Gulf
of Mexico which would not be developed absent these
incentives. In addition, the Department of the Interior
will continue to review its leasing policies in mature
areas to ensure these policies are appropriate for
changing economic conditions and new economic challenges.
60
The Department of the Interior is committed to working
with stakeholders at the state and local level to attempt
to resolve issues raised in connection with exploration
and development of existing leases. Stakeholders, in
some instances, may include local representatives of
various Federal agencies.
61
QUESTIONS FROM REPRESENTATIVE ORTIZ
Domestic Oil and Gas Initiative
Question 2: (a) Does deep water or frontier area drilling and
production pose any additional environmental risks?
The most significant environmental risk associated with
deep water drilling is the threat of a pollution
incident. The Department of Energy, in agreement with
the Department of the Interior, does not anticipate that
any qualitatively new type of environmental risks would
result from an increase in gas and oil production in the
deep water OCS. In fact, an increase in domestic OCS
production may provide some environmental benefits by
reducing the need for imported oil and the concomitant
threat of oil spills associated with international tanker
traffic.
It is important to note that over the past two decades,
there has been a considerable decline in the number of
oil spills originating from offshore facilities in the
OCS. The Minerals Management Service reports that the
number and total volume of pollution incidents in the
Gulf of Mexico OCS has steadily fallen from 183 spills
representing a total of 23,125 barrels in 1973, to the
most recent report of 25 incidents representing a total
of 2,804 barrels in 1992.
"7A-*A1 O - 93 - 3
62
This trend can be attributed to significant advancements
in offshore gas and oil drilling technology, improvements
in spill recovery techniques, and the OCS leasing and
permitting program administered by the Minerals
Management Service. The Department of Energy believes
that this reduction in the number of oil spills further
illustrates that gas and oil production from both deep
and shallow water regions of the OCS can be accomplished
in a safe and responsible manner. It should also be
noted that communities in frontier areas have outstanding
concerns regarding other environmental impacts associated
with OCS development such as drilling discharges, rig
emissions, and the onshore industrialization that
accompanies off-shore development. It is unlikely that
these communities will support new OCS development until
these concerns are addressed.
Question 2(b): Does this legislation impact any existing
environmental protections, laws, regulations,
permits, etc.?
Answer: The Department of Energy does not believe this
legislation will adversely affect any existing
environmental regulations applicable to OCS gas and oil
operations.
63
QUESTIONS FROM REPRESENTATIVE FIELDS
Domestic Gas and Oil Initiative
Question 5: Will the Domestic Gas and Oil Initiative look at
incentives such as this bill as well as tax
. incentives?
Answer: The Department of Energy will continue to look at a range
of options to increase oil and gas production in an
economic and environmentally sound manner. H.R. 1282 —
the "Outer Continental Shelf Enhanced Exploration and
Deep Water Incentives Act" — is similar to options which
are being considered. The Department is examining costs
and benefits of various ways to more productively manage
nationally-owned assets, and is exploring changes in the
tax code.
«
Incentives such as lower royalties will be considered for
the deep water portions of the western and central Gulf
of Mexico which would not be developed absent these
incentives. In addition, the Department of the Interior
will continue to review its leasing policies in mature
areas to ensure these policies are appropriate for
changing economic conditions and new economic challenges.
The Department of the Interior is committed to working
with stakeholders at the state and local level to attempt
to resolve issues raised in connection with exploration
and development of existing leases. Stakeholders, in
64
some instances, may include local representatives of
various Federal agencies.
65
Testimony submitted by
Robert B. Stewart
President
National Ocean Industries Association
before the
Oceanography, Gulf of Mexico and OCS Subcommittee
Merchant Marine and Fisheries Committee
September 14, 1993
66
Good afternoon Mr. Chairman and members of the Subcommittee. Thank you for the opportunity
to testify. By way of introduction, NOIA is the only national trade association that represents all
facets of the domestic offshore oil and natural gas industry. Our more than 280 corporate
members range from major and independent producers to drilling contractors, service and supply
companies, manufacturing companies, the telecommunications industry and the financial industry.
We are joined in this statement by the International Association of Drilling Contractors, the
International Association of Geophysical Contractors and the Petroleum Equipment Suppliers
Association.
I appreciate your holding this hearing today and welcome Mr. Fields* efforts to revive our
industry through the introduction of this legislation. As you are well aware, our industry has lost
more than 450,000 jobs in the past decade, and domestic oil production has fallen below 50
percent of demand. While we currently are experiencing a modest increase in drilling over last
year, a greater commitment from the government is needed to stimulate industry activity, halt
job losses and improve our domestic oil and gas reserve picture. Enacting production incentives
legislation would be a first step down the road to recovery. I will discuss other areas of
commitment later in my statement.
NOIA supports the purpose and intent of H.R. 1282, the Outer Continental Shelf Enhanced
Exploration and Deep Water Incentives Act. The bill's provisions provide benefits and
opportunities to the domestic offshore industry. However, while royalty relief may tip the scales
in favor of an otherwise marginal project, additional incentives, such as production tax credits,
would be needed to impact substantially near-term activity in the deepwater Gulf of Mexico.
67
Industry has made technological advances that make development of deepwater oil and natural
gas feasible. However, at today's oil and gas prices, many deepwater discoveries are not being
developed due to marginal economics resulting from the high costs associated with this unique
deepwater setting and the attendant extraordinary economic risks. Up-front costs for deepwater
development are extremely high compared to development costs in shallower water. Full field
development can exceed $1 billion. Deepwater production experience is fairly limited, the
geology is more complex than in more mature offshore areas and a significant use of high-cost
three-dimensional seismic surveys is required in addition to more sophisticated drilling and
completion tools. An incentives package including production tax credits and royalty relief could
result in substantial development in these areas.
As an example of the potential economic stimulation generated by deepwater activity, one of our
member companies is developing a prospect from which initial production is anticipated early
next year. As of May 1992 more than 900 vendors in 33 states had received contracts on this
$1.2 billion project. It is estimated that more than 2,850 people will be employed domestically
at one time or another in this project. The impact of this project is even more far-reaching if you
consider the next tier of vendors receiving subcontracts from the direct contractors. The number
would multiply significantly.
Stimulating new offshore development has significant employment implications. We estimate that
for every $1 million invested offshore, 20 jobs are created. And, for every 10 jobs created
offshore, 37 jobs are created onshore. There are thousand of workers in need of the jobs that
these deepwater incentives would create. Congress has the ability through these types of
68
proposals to put many of these people to work. It is time to create these jobs.
We believe that clarifying the Fields' bill to include incentives for each phase of development
could create more projects like the one I just mentioned. Massive up-front costs in many cases
dictate the use of multiple phases for development. For example, a small facility would be
installed to drill and produce initial production wells to test the reservoir. If the reservoir
produces as expected, a permanent facility would be constructed and installed. Additional
production facilities may be required if full production cannot be handled by the initial permanent
production facility. Each of these phases should be taken into account in considering the nature
and extent of incentives to stimulate new exploration and production.
The beneficial impact of the deepwater Gulf of Mexico was recently confirmed by a study
sponsored by a group of NOIA members interested in the Gulf of Mexico slope. The DRI study
found that incentives that spurred the development of 2 to 7 billion barrels of oil equivalent
reserves would by 1998 result in 56,000 to 105,000 new jobs, increase cumulative federal
revenues $6 to $10 billion and improve the country's foreign trade balance.
In short, we believe H.R. 1282, together with additional incentives, would help increase domestic
energy production, could create thousands of new jobs and generate billions of dollars into the
economy.
In addition to Congressional proposals, the Administration can take certain actions that would
boost domestic production. For example, as H.R. 1282 would clarify, we believe the Secretary
69
of the Interior has the authority to reduce or suspend royalty payments prospectively - specifically
on leases that have been drilled and upon which discoveries have been made, but which are
unlikely to be developed because of the small size of the discovery and the resulting marginal
economics. We believe that the OCS Lands Act provides the Secretary with this authority, and
this authority should be exercised. Section 5(a) of the Act gives the Secretary broad power to
"prescribe such rules and regulations as may be necessary" to carry out the Act. Additionally,
Section 8(aX3) of the Act states, "The Secretary may, in order to promote increased production
on the lease area, through direct, secondary or tertiary recovery means, reduce or eliminate any
royalty or net profit share set forth in the lease for such area." Clearly, if such action is taken by
the Administration, at least some of the goals of H.R. 1282 would be met.
One action taken by the Administration that may benefit our domestic energy picture is Secretary
O'Leary's Domestic Energy Initiative. As we said in our comments on the Initiative, it is
imperative that environmental regulatory costs are balanced by the environmental benefits that
result from the requirements. We are anticipating the release of this initiative later this fall.
We also commented to Secretary O'Leary that it appears the government at times works at cross
purposes with itself regarding energy policy. One of the problems we face is the lack of
reliability of the federal government as a business partner. Congress has placed most of the OCS
under leasing moratoria ostensibly so that environmental studies could be performed to determine
the effects of offshore development. Then Congress denies funding for the studies since no
leasing is scheduled in those areas. In fact, the MMS Environmental Studies Program budget was
reduced by 40 percent for FY 94. The National Research Council said last year's funding level,
70
prior to the 40 percent reduction, was barely adequate for MMS to meet its mandate. This looks
like a catch-22 to us.
Another problem with reliability is the federal government, through drilling moratoria, has
prevented federal lessees from exploring leases that they bought and paid for in good faith. As
we have previously testified before this Subcommittee, we believe the federal government should
take responsibility for its actions by providing full and prompt compensation to those lessees.
In addition, some of the areas that have been placed under moratoria have a high potential for
natural gas discoveries. While we support the Clinton Administration's goal of increasing the
demand for natural gas, we have to have new supplies to meet that demand. At present, we are
producing at near capacity and have to import some gas from Canada. The Energy Information
Agency recently predicted a 26 percent jump in Canadian gas imports, rising to 2.4 trillion cubic
feet in 1994. We have the technology and the reserves to accommodate an increase in demand,
but are prohibited from doing so by the Congress. Removing disincentives, receiving a solid
energy policy from the Administration and enacting incentives legislation would benefit this
industry and the nation as a whole with jobs and increased domestic energy production.
In closing, again I appreciate this opportunity to testify today. We are supportive of incentives
proposals and offer ourselves to help in any way this Subcommittee feels would be beneficial.
I will try to answer any questions you may have.
71
j*
INDUSTRY
NATIONAL OCEAN INDUSTRIES ASSOCIATION
^^ ^FP 1120 G Street, N.W., Suite 900, Washington, DC 20005 (202)347-6900 FAX (202) 347-8650
Robot B. Stewart
President
October 5, 1993
The Honorable Solomon P. Ortiz
Chairman
Subcommittee on Oceanography,
Gulf of Mexico, and the
Outer Continental Shelf
Room 1334
Longvorth House Office Building
Washington, D.C 20515-6230
Dear Mr. Chairman:
Once again, please accept my thanks for inviting the National
Ocean Industries (NOIA) to present testimony at the Subcommittee's
September 14 hearing on incentives for deep water oil and natural
gas development. I have received two sets of written questions
pertinent to the hearing, on from you on behalf of the Subcommittee
and one from Mr. Fields the author of the legislation in question
(H.R.1282). Responses to both sets of questions are enclosed. If
you have further questions you would like us to address please feel
free to contact me.
NOIA looks forward to the opportunity to work with the
Subcommittee and its staff to craft legislation that will stimulate
investment in OCS oil and natural gas exploration and development.
Sincerely,
'SiJ^JhuJ'
Robert B. Stewart
Enclosures
72
Responses to questions from the hearing on incentives for offshore
oil and gas production.
1. Question: What effect will the proposed incentives have
on industry's willingness to develop deep water or
marginal areas? Response: Companies typically have more
potential projects world-wide than they have capital to
invest. Companies will choose those projects that are
economically the most attractive. The presence of
incentives will increase the economic attractiveness of
working in U.S. waters and should increase the level of
investment in such projects.
2. Question: What can be done to stimulate deep water or
marginal areas without legislation? Response: This
question would be more appropriate for an operating
company than for a trade association. There may be some
Secretarial discretion to alter lease terms in ways that
would encourage development of these areas.
3. Question: Do you feel that providing royalty relief will
induce enough new development, that would not otherwise
take place, to make such a proposal justified in terms of
protecting federal revenue? Response: I believe it is
possible to design an incentives package that will meet
that standard.
4. Question: What is your opinion on the proposal presented
by MMS to consider royalty relief on a "case-by-case"
basis? Response: MMS currently has "case-by-case"
authority on producing leases. We believe that authority
extends to inducing development of non-producing leases,
though that issue is currently under study by the
Department of the Interior's Solicitor. One problem with
the case-by-case approach is the level of administrative
burden on the Department and on the applicant. The
burden on the applicant may be great enough to outweigh
the economic benefit of royalty relief.
5. Question: Does deep water or frontier area drilling and
production pose any additional environmental risks?
Response: Existing technology, training and regulations
assure that these projects will not pose undue risks to
the environment. It can be argued that because these
projects are father from shore, the risks are reduced.
6. Question: Does this legislation impact any existing
environmental protection, laws, regulations, permits,
etc. Response: I do not believe this legislation will
have any such impact.
73
Question: MMS has proposed that the Secretary set a
schedule of allowable capital costs rather than actual
costs. What is your opinion on this proposal?
Response: If regulatory simplicity is the object of this
proposal, it may veil have merit provided it does not
diminish the stimulative value of the incentive contained
in the legislation.
Question: Would this legislation have any impact on
unl eased tracts in deep water areas within the Gulf, or
do you believe that most of the promising areas are
already under lease? Response: The impact of this
legislation on unleased acreage should be to make it
economically more attractive to prospective lessees than
at present. By no stretch of the imagination are most of
the promising areas of the deep water Gulf of Mexico
already under lease. Think of the deep water Gulf of
Mexico as a frontier area; lightly explored, little to no
infrastructure, complex and not fully understood geology
and mostly unleased.
74
Responses to questions put to industry witnesses from Congressman
Jack Fields (R-Texas) Oceanography Subcommittee Hearing, September
14, 1993.
These responses are those of Robert B. Stewart, President of the
National Ocean Industries Association. A number of the questions
posed by Mr. Fields are appropriate for individual companies but
are not answerable by a trade association such as NOIA. We will
address those questions we believe we can answer.
1. With respect to the first three questions pertaining to
domestic exploration budgets versus exploration spending
abroad, we attach a chart showing recent industry trends.
Specific data will have to come from individual
companies .
2. Question: Are there any areas outside the Gulf where
some type of royalty relief should be offered? Response:
The only area still open to leasing and development
outside the Gulf is offshore Alaska excluding the North
Aleutian Basis Planning Area. Consideration should be
given to Alaska and such other areas as may become
available in the future.
3. Question: If some type of incentive is not available,
how cost effective is it to explore Arctic areas?
Response: This is a question best answered by companies
with experience in arctic exploration and the economics
of working in that part of the world.
4. Question: Obviously, the cost of technology to develop
deep water areas is high. What other technologies such
as air quality controls add significant costs to a
development project and should be considered for royalty
relief? Response: There are limits to what royalty
relief can do to offset costs. It would help if a way
could be found to assure that those burdens are sensible
scientifically and bear a relationship to the perceived
environmental problem.
5. Question: What other incentives should be considered to
make deep water development cost effective? Response:
Some have suggested that production tax credits coupled
with royalty relief would be necessary to spur
development in the deeper areas of the Gulf.
6. Question: Would it influence your lease purchasing
decisions to know at the lease sale whether a lease were
eligible for royalty relief? Response: This question is
better put to a producing company. I would surmise that
it might make a difference.
75
7. Question: In your opinion, does the Secretary have the
ability to reduce or suspend royalties and is that
authority used? How could that authority be expanded to
make it more available? Response: The Secretary clearly
has authority under the OCS Lands Act to suspend or
reduce royalties on producing leases in order to prevent
premature abandonment of production. We also believe
that same authority exists in order to promote
development of non-producing leases. We understand this
question is currently under review in the Solicitor's
Office at the Department of the Interior. This authority
has rarely been used. In the case of a producing lease
we suspect the benefit of royalty relief is overwhelmed
by the costs and time necessary to apply for it. The
Secretary's authority in the case of non-producing leases
could be legislatively clarified. Further, expanded
authority such as proposed in Mr. Fields' bill could be
extended to enable the Secretary to grant relief on the
basis of geologic basins or trends rather than on a tract
by tract basis.
8. Question: Would it be more effective if the Secretary
could grant royalty suspension of relief before
production began? Response: Yes. The earlier in the
process, the better and the more broadly geographically,
the better.
9. Question: If moratoria continue off the Pacific and
Atlantic coasts, what areas are there left for
exploration? Response: In this country, the Gulf of
Mexico and Alaska excepting the North Aleutian Basin
Planning Area. Even the Eastern Gulf of Mexico Planning
Area is becoming increasingly controversial.
10. Question: Given our need to offset losses to the U. S.
Treasury if OMB and CBO project that the legislation will
negatively impact the treasury, what suggestions do you
have to bring the cost of this legislation down? Is
there anything that can be done to help increase deep
water production without directly effecting the budget?
Response: If the legislation is designed so that the
bulk of the projects receiving incentives are those that
would not go forward in the absence of help, then the
treasury gains rather than loses. Tax and royalty
streams (after capital cost recovery in the case of
royalties) would flow to the Treasury in amounts that
would not occur in the absence of incentives.
76
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77
WRITTEN TESTIMONY
PRESENTED BY
EXXON COMPANY, U.S.A.
BEFORE THE
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF MEXICO, AND
THE OUTER CONTINENTAL SHELF
UNITED STATES HOUSE OF REPRESENTATIVES
WASHINGTON, D.C.
SEPTEMBER 14, 1993
Mr. Chairman, my name is Mike Flynn. I am the Manager of Exxon U.S.A.'s Southeastern
Production Division located in New Orleans, Louisiana, which is responsible for Exxon's
producing activities, both onshore east of Texas and in the Gulf of Mexico (GOM). I appreciate
this opportunity to discuss the GOM and the need for incentives to encourage its exploration and
development.
Our Division currently produces 90 thousand barrels of hydrocarbon liquids per day and 750
million cubic feet per day of natural gas. Approximately 65% of this production comes from the
offshore GOM. This will increase by 200 million cubic feet per day this year when we begin
production from our $1 .2 billion, very deep sour gas development in Mobile Bay. We employ
1500 people, operate about 100 offshore platforms, and constitute about 25% of Exxon's
domestic production.
Our Division's responsibility is to successfully develop new opportunities in technologically
challenging areas such as Mobile Bay and the GOM Slope. The GOM Slope (leases beyond a
water depth of 200m (656 feet)) is thought to be the province containing the largest undiscovered
petroleum resource in the nation in an area open to exploration and development. The
Department of Interior (1991) estimates remaining undiscovered resources of 4.1 billion barrels of
crude and 44 trillion cubic feet of gas (totaling nearly 12 billion oil equivalent barrels). This
78
compares to the 12 billion barrels ultimately recoverable from the Prudhoe Bay field which
currently provides 18% of U.S. oil production.
These large estimates of remaining potential undiscovered resource for the GOM Slope are
supported by results to date. The petroleum industry has under lease from the Minerals
Management Service (MMS) 1 1 million acres and, according to Exxon's estimates, has already
discovered 5 billion oil equivalent barrels (OEB) in about 90 fields. Approximately half of the
resource discovered to date is natural gas.
Today it is unclear how much exploration effort will be focused on the 12 billion OEB of
undiscovered potential or how much of the 5 billion OEB of current discoveries will be developed.
Due to unusually high geologic risks combined with high up-front investment requirements and
uncertain oil and gas prices, even the largest companies may not be able to justify proceeding at
the pace dictated by current MMS leasing terms given today's royalty and tax systems. Nearly 4
billion OEB or 80% of the already discovered volume is in a water depth of 400m (1312 feet) or
greater, which is generally beyond the limit for conventional steel-pile jacketed platforms.
Consequently, in these deeper water depths, only 10 fields containing less than 1 billion OEB are
currently producing or are committed to development. This leaves an already discovered 3 billion
OEB as future opportunity.
For additional perspective, I would like to provide some background on these high risks and costs
by describing Exxon's GOM Slope activities over the past several years.
Exxon has made a substantial commitment to the GOM Slope and is vitally interested in seeing
this commitment benefit both the nation and Exxon. We are the third largest leaseholder in the
deepwater GOM with over 1.2 million acres leased. To date we have spent about $3 billion, 30%
of this for lease bonuses paid to the Department of Interior. Exxon has drilled 57 prospective
Gult ol Mexico Slope 2 09/1 1 S3
79
accumulations in the GOM Slope and made 1 1 discoveries with commercial development
potential for a success ratio of just 20%. Four of these are developed and on production while
seven are under evaluation for possible development.
Our first development was the Lead field (Mississippi Canyon 31 1 ) located just at the break point
between the Continental Shelf and Slope. This 100 million OEB field was developed using a
conventional steel piled jacket and began production almost 15 years ago in 1979. Some of the
reservoirs producing in this field have lower quality deepwater rock characteristics. They have
proved to be good producing intervals and encouraged further developments.
Our next deepwater GOM development, the Lena field (Mississippi Canyon 281), located in 1000
feet of water, was developed using industry's first guyed tower. This 75 million OEB field came
on production in 1984. The tower and original wells cost about $575 million. While the guyed
tower cost and performance have been as predicted, the Lena reservoirs were much more
complex than initially expected. As a consequence, more producing wells than planned were
required to recover the hydrocarbons. In addition, the crude price has been far less than
anticipated when the field development decision was made. Hence, if we were faced with the
same decision today, absent royalty and tax incentives, the Lena field either would not be
developed or would be developed using a smaller platform with fewer wells and recovering fewer
reserves.
Alabaster (Mississippi Canyon 397) and Zinc (Mississippi Canyon 354) are our most recent
developments. While Alabaster's reservoirs lie under water depths of 1000 to 1500 feet, the
existence of a nearby underwater knoll allowed development with a conventional steel piled
jacket located in 470 feet of water. Zinc, which is located six miles from Alabaster, is in 1500
feet of water and is being developed with a multiwell subsea production system. Gas and liquid
production from Zinc flows by a single pipeline to the nearby Alabaster platform for processing
Gulf of Mexico Slope 3 09/1 1 S3
80
and product disposition. These two gas fields contain about 500 billion cubic feet of natural gas
and will require an investment of about $600 million to develop. If it were not for the fortuitous
knoll, the economic development of reserves of this size, located in 1500 feet or more of water,
would not be possible without royalty and tax incentives. These fields are just now coming on
production.
While Exxon has developed four GOM Slope fields in water depths to 1500 feet, our next step
will likely be quite substantial. The seven discoveries which we have yet to develop are in water
depths ranging from 2500 feet to 4600 feet. Reserve sizes range from about 50 to over 200
million OEB. Due to the water depth, development costs excluding exploration are high, ranging
to over $8 per barrel. Also, lead times are long requiring large monetary outlays many years in
advance of revenues. In order to successfully develop and produce oil and gas under such
conditions, we and other field owners are exploring several development approaches utilizing
new and emerging technologies and including multifield development alternatives. Prior to
discussing key Exxon opportunities, some background on the broader development issues as we
move out into deeper waters may be helpful.
As a result of our experiences and studies, we believe prospective reservoirs underlying the GOM
Slope were deposited by currents containing suspended sediments flowing downslope on the
ancient ocean floor. Some of these reservoirs have been subjected to complex structuring and
salt movement. Industry experience in producing these stratigraphically complex reservoirs is
very limited.
In this difficult geologic environment, a significant amount of time, typically several years, is
required in the utilization of three-dimensional seismic studies, in delineation drilling and in
development planning in order to optimize development and reduce unsuccessful investments.
GuHofMuoco Stops 4 08/11/93
81
Conducting a three-dimensional seismic study, considered alone, is a time and people intensive
effort for acquisition, processing, interpretation, and reinterpretation as wells are drilled.
Even after a large prospect is adequately delineated, site-specific applications require time to
develop. Beyond 400m, development requires production systems (Tension Leg Platform,
Floating Production System, Subsea Production System, Compliant Piled Tower) whose
technology is proven but evolving quickly. Large facility investments ($500 million range) are
required before initiation of production and before reservoir performance information is obtained.
Total single field investments can range between $1-2 billion, which is greater than the net assets
of all but about 50 U.S. oil and gas companies. With so many systems to evaluate, a fairly long
period is expected before an operator would know which technology is most suited for each
prospect. Similarly, given industry's limited experience in the deepwater GOM Slope, there is still
a relatively high level of uncertainty on the projections of capital and operating costs. History
shows that usually cost optimizations can be devised as site-specific designs are considered.
Considering the high initial costs, companies will often need to share infrastructure and facilities
by pursuing cooperative, multifield development. For example, stand-alone fields in shallow water
may be economic with reserves of 50-60 million OEB. Yet, in water depths just beyond
conventional platform technology (>400m), a field size of 100+ million OEB may be required for
development at current prices considering the risks involved. In 1000m water depth, this
increases to around 200 million OEB. These thresholds can vary depending on the location,
relative amounts of oil versus gas, reservoir quality, and other factors such as the availability of
existing infrastructure. We estimate that about half the volume discovered to date on the GOM
Slope is contained in fields smaller than 100 million OEB and will require creative approaches to
enhance attractiveness. Some may become viable as a part of a multifield development.
Gulf of Mexico Slope
82
Producers will need the flexibility to combine fields in order to accumulate economic volumes.
However, the relatively small OCS tract size (5760 acres) and typical development requirements
that are keyed to individual lease maintenance requirements detract from the industry's ability to
capture multifield development synergies. Industry is working on lease flexibility concepts that
would recognize the unique nature of the GOM Slope and facilitate optimum paced development.
The concepts focus on area-wide development planning, recognizing that geologic and economic
interrelationships exist between drilled or undrilled leases in the deepwater setting.
To illustrate some of the challenges being faced in the GOM Slope, I will discuss three of Exxon's
currently undeveloped prospects.
The "Ram/Powell" field (Viosca Knoll 912) is located in 3300 feet of water and is believed to
contain over 200 million OEB. The field owners, Exxon, Shell and Amoco, are designing a
tension leg platform for development. Total costs, if developed, could be around $1 billion.
However, there is still optimization being pursued. The development plan being considered
includes only the highest quality reservoirs. There are lower quality reservoirs that we may not
develop initially and possibly not at all, given the current fiscal system and risks. In planning the
development, this "highgrading" is necessary to reduce investment and improve the chances of
achieving economic success. Obviously, with lower royalty and federal taxes, more marginal
reserves could be pursued.
Another field that we have under evaluation is located in 3000 feet of water in the Green Canyon
area. To date only the discovery well has been drilled. We and the other field owner, Shell, will
need to drill delineation wells to better understand the size and quality of the reservoirs in this
prospect. Such wells can cost over $20 million each. Thereafter, we will be evaluating various
development alternatives, one of which is the potential development of this prospect as a
satellite to a nearby currently producing platform. This option would be available when existing
Gutf o< Memco Slope 6 09/11*93
83
production declines in the future. Our ability to take advantage of these opportunities when they
exist is dependent not only upon site-specific technical and economic considerations, but also on
leasehold flexibility provided by the MMS.
The final field I will comment on is "Mickey" (Mississippi Canyon 211), located in 4400 feet of
water. It was discovered by Exxon in 1990 by drilling through a 3000 foot salt sill and will also
require further delineation. Through new technology in high effort seismic, we were able to
image these reservoirs below the salt sill prior to drilling. This was the first deepwater subsalt
well drilled by industry and opened up significant new potential for ourselves and the rest of
industry.
Even with lease term and administrative changes that allow creation of a viable development
opportunity, royalty and tax incentives are still needed to encourage industry to more quickly
invest shareholders' money in the high-risk GOM Slope.
We encourage the intent and purpose of HR 1282, the Outer Continental Shelf Enhanced
Exploration and Deepwater Incentives Act and appreciate the efforts of the sponsors and this
Subcommittee. It recognizes the GOM Slope's large potential resource and the associated high
geologic and economic risks in this frontier area. However, while HR 1282 would benefit these
deepwater developments, alone this would not be sufficient. Additional incentives such as the
deepwater production tax credit of $5/OEB contained in Senator Breaux's proposed bill S.403 are
needed to encourage substantial additional development and exploration activity in the near term.
Incentives that are nondiscriminatory between producers, structured to reward successful efforts,
and apply to new production from existing and new deepwater leases can be effective in the near
term and benefit the nation as a whole. Since they are results oriented and encourage
investment, government can receive more revenue over time than it potentially gives up.
Gulf o( Mexico Slope 7 09m/93
84
A recent economic study, prepared by the consultants, DRI/McGraw-Hill, and sponsored by an
industry working group on deepwater GOM incentives, indicates that a $5/OEB production tax
credit, such as provided in bill S.403, that spurred the development of 2-9 billion OE8 of reserves
would by 1998 result in 56,000-105,000 new jobs, increase cumulative federal revenues $6-10
billion, and improve the annual foreign trade balance. Moreover, the study indicated the
cumulative federal impact would never be negative. This would hold true because the necessary
up-front investment would produce additional corporate taxes before the production tax credit
would be allowed.
In closing, I want to say we appreciate the opportunity to present this testimony to the
Subcommittee. We are supportive of targeted, results oriented incentives for resources like the
GOM Slope that have significant potential to be beneficial to the nation as a whole. We believe
that royalty relief combined with a production tax credit, together can impact GOM Slope
development in a meaningful way. Also working with industry and the MMS, we believe lease
term flexibility can be improved to allow efficient, economic resource development.
Quit otMndco Slops
85
PROFESSIONAL BIOGRAPHY
MR. M. E. (MIKE) FLYNN
EXXON COMPANY, U.S.A.
PRODUCTION DEPARTMENT
SOUTHEASTERN DIVISION MANAGER
Mike Flynn began his career in New Orleans, Louisiana in 1973 in the Production
Department of Exxon USA after receiving a degree in Mechanical Engineering from
Texas A&M University. In 1978, after various engineering and supervisory
assignments along the Gulf Coast, he moved to Exxon Production Research Company
in Houston where he consulted with Exxon affiliates worldwide. In 1983 he returned to
Exxon Company, U.S.A. to manage design of the LaBarge facilities in Wyoming. In
1986 he became the Southwestern Division's Operations Manager in Midland, Texas.
He later moved to Houston to become the Crude Oil Manager in the Supply Department
and played a major role in establishing Exxon Supply Company in 1989. He went to
work for Exxon Corporation in 1990 as an Upstream Advisor. In 1992 he returned to
Exxon Company, U.S.A. as a Production Division Manager located in New Orleans,
Louisiana. Mike is a member of the Executive Committee of the Mid-Continent Oil and
Gas Association (MOGA), Mississippi/Alabama Division and is an Area Vice President
of the Louisiana Division of MOGA. He is also on the Board of Directors of Junior
Achievement of Greater New Orleans and sits on the New Orleans Business Council.
86
EJgON COMPANY, U.S.A.
POST OFFICE BOX 61707 • NEW ORLEANS. LOUISIANA 70161-1707
PflOOUCTKM DEPARTMENT
sootwastctnoivokw October 7, 1993
The Honorable Solomon P. Ortiz, Chairman
Subcommittee on Oceanography, Gulf of Mexico,
and the Outer Continental Shelf
House Committee on Merchant Marine and Fisheries
575 Ford House Office Building
Washington, D. C. 20515
Dear Chairman Ortiz:
I appreciated the opportunity to appear before the Subcommittee to
discuss the resource potential in the deeper waters of the Gulf of
Mexico and the need for incentives to stimulate exploration and
production activity in these areas.
Attached are responses to the written questions submitted by you and
Representative Fields. Also attached is my response to Representative
Green's question at the hearing about the jobs associated with the
Alabaster and Zinc projects.
If you have additional questions, please contact me or Don Smiley, Vice
President of Exxon's Washington Office.
Sincerely,
M. E. FLYWp
DIVISION 'MANAGER
MEF
Attachments
w/attachments
The Honorable Jack Fields
The Honorable Gene Green
Mr. D. E. Smiley
A DIVISION OF EXXON CORPORATION
87
EXXON RESPONSES TO QUESTIONS FROM CHAIRMAN OF
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF MEXICO,
AND THE OUTER CONTINENTAL SHELF
Ql. What effect will the proposed incentives have on industry's
willingness to develop deep water or marginal areas? What can be
done to stimulate deep water or marginal areas without
legislation?
Al. Exxon believes that targeted incentives, such as the royalty
relief contained in H.R. 1282 when coupled with the production tax
credit of $5 per oil equivalent barrel contained in S. 403, would
encourage substantial additional development and exploration
activity in the near term.
While additional lease term flexibility would facilitate optimum-
paced development, Exxon believes production incentives are needed
to encourage substantial additional development and exploration
activity in the near term.
Q2. Approximately what percentage of your company's total exploration
and development budget goes to foreign projects? Will this
legislation help to bring some of this money back to the U.S.?
Will the development of these deep water areas be accomplished
through the use of U.S. service companies?
A2. Exxon's capital and exploration expenditures for the upstream
(exploration, production and related transportation) totaled $5.2
billion in 1992 of which about two-thirds was for activities
outside the United States.
U.S. opportunities stand on their own merit, and Exxon has
adequate capital resources for quality opportunities anywhere in
the world. Exxon would like to invest in U.S. exploration and
production, but most of the attractive prospective acreage in this
country is not available for exploration or development.
No one can be certain or guarantee that production incentives will
shift exploration and development expenditures to the U.S. because
many factors enter into these decisions. However, there are
significant, already-discovered resources in the deeper waters of
the Gulf of Mexico, and this is thought to be the province
containing the largest undiscovered petroleum resource in the U.S.
in an area still open to exploration and development. Exxon
believes targeted incentives would help encourage substantial
additional exploration and development activity in the near term.
88
Based on past experience, companies, including service companies
throughout the U.S., are likely to gain business and therefore
benefit from deepwater development. The greatest impact would
likely be in the states adjacent to the Gulf.
Q3. Does deep water or frontier area drilling and production require
any additional environmental safeguards? If there are any, what
are your companies doing to address these safeguards? Has there
been any research completed to address this issue?
A3. Exxon believes existing technology is well proven and permits
drilling and production in deeper waters in an environmentally
safe manner. Existing regulations are adequate to protect the
deep water environment.
There has been much research undertaken to enhance our
understanding of the physical deep water environment, including
water currents, seafloor conditions and topography. The results
of this research have been incorporated into the design,
construction, placement and operation of deepwater structures.
89
EXXON RESPONSES TO QUESTIONS FROM
THE HONORABLE JACK FIELDS
Ql. How much of your current exploration budget is spent in the U.S.?
Al. Exxon's worldwide exploration expenditures in 1992 totaled $977
million of which $171 million was for U.S. activities.
Q2. How does that compare with ten or fifteen years ago?
A2. Ten years earlier, in 1982, worldwide exploration expenditures
totaled $2.6 billion of which $1.5 billion was for U.S. activities.
Of the $1.5 billion, $0.4 billion was for lease bonus payments in
expectation of much higher energy prices. The remaining $1.1
billion was for activity comparable to the $171 million in 1992.
Q3. If other incentives such as tax credits were offered would that
change your decision to go abroad with your exploration budgets?
A3. U.S. opportunities stand on their own merit, and Exxon has adequate
capital resources for quality opportunities anywhere in the world.
Exxon would like to invest in U.S. exploration and production, but
most of the attractive prospective acreage in this country is owned
by the federal government and is not available for exploration or
development.
No one can be certain or guarantee that production incentives will
shift exploration and development expenditures to the U.S. because
many factors enter into these decisions. However, there are
significant, already-discovered resources in the deeper waters of
the Gulf of Mexico, and this is thought to be the province
containing the largest undiscovered petroleum resource in the U.S.
in an area still open to exploration and development. Exxon
believes targeted incentives would help encourage substantial
additional exploration and development activity in the near term.
Q4. Are there any areas other than the Gulf where some type of royalty
relief should be offered?
A4. Exxon supports incentives to encourage new or the significant
expansion of enhanced oil recovery projects. A $5 per oil
equivalent barrel tax credit for enhanced oil recovery projects
could encourage the development of about 3 billion oil equivalent
barrels over 20 years.
90
Q5. If some type of incentive is not available, how cost effective is it
to explore Arctic areas?
A5. A significant impediment to Arctic investment is the lack of access
to the Arctic National Wildlife Refuge (ANWR). Exxon believes there
is sufficient potential for undiscovered resources in ANWR and other
Arctic areas that it would be in the nation's interest for these
areas to be explored.
In those high-risk, high-cost areas available for development today,
just as in the deep water Gulf of Mexico, targeted incentives, such
as royalty relief and tax incentives, would help encourage
additional exploration and development activity.
Q6. Obviously the cost of technology to develop deep water areas is
high. What other technologies such as air quality controls add
significant costs to a development project and should be considered
for royalty relief?
A6. Environmental regulations add significantly to the cost of offshore
development and, for this reason, should be cost effective and based
on scientifically-sound risk assessments. Since oil and gas
production facilities in the Gulf of Mexico do not usually generate
significant concentrations of air pollutants, existing regulations
are adequate to protect the deep water environment.
Q7. What other incentives should be considered to make deep water
development cost effective?
A7 Exxon does not believe the royalty relief provisions of H.R. 1282
alone are sufficient to encourage substantial additional development
and exploration activity in the deeper water of the Gulf of Mexico
in the near term. Additional incentives such as the deep water
production tax credit of $5 per oil equivalent barrel contained in
S. 403 are needed.
Q8. Would it influence your lease purchasing decisions to know at the
lease sale whether a lease were eligible for royalty relief?
A8. Yes. To the extent that royalty relief can be anticipated before
the lease sale, one element of uncertainty would be removed.
Royalty relief certainly is a step in the right direction. However,
as noted in our statement, royalty relief alone would not be
sufficient to encourage substantial additional deep water
exploration and development.
91
Q9. In your opinion, does the Secretary have the ability to reduce or
suspend royalties and is that authority used? How could that
authority be expanded to make it more available?
A9. It is Exxon's opinion that the statutory language gives the
Secretary the ability to reduce royalty for future lease sales in
order to promote more expeditious exploration of the lease area and
also to reduce or even eliminate existing royalty terms in order to
promote increased oil and gas production on federal leases where
there is existing production.
Experience indicates that MMS has reduced royalties only on a
case-by-case basis where premature abandonment of a producing lease
would otherwise occur. This happens late in the productive life of
the reservoir and thus is not a significant consideration in
bringing new reserves into production.
Increasing flexibility to adjust royalties can be accomplished
through a more liberal application of the existing law and
regulations by MMS. Minor changes to 30 CFR §203. 50(b) would be
beneficial to clarify the intent that an application for royalty
reduction can be initiated at an earlier stage than present
practice.
Q10. Would it be more effective if the Secretary could grant royalty
suspension or relief before production began?
A10. Yes. Royalty and tax incentives granted before exploration or
development begins decreases the reserve size needed to generate an
economically successful development and therefore generates
additional activity. Incentives granted only after production rates
prove a development as economically marginal do not materially
stimulate exploration and development activity, although some
marginal production could be maintained.
Qll. If moratoria continue off the Pacific and Atlantic coasts what
areas are there left for exploration?
All. Exxon believes the United States should encourage domestic oil and
gas production by granting access to all promising OCS and onshore
areas, including the Arctic National Wildlife Refuge. Exxon
believes exploration and development in these areas can be
undertaken in a safe and environmentally responsible manner, would
stimulate economic growth, provide jobs and increase local, state
and federal revenue.
In the meantime, any expansion of the moratoria areas should be
avoided. Inland and the shallow water Gulf of Mexico can still
support sizable economic activity. However, they do not hold the
potential for large reserves when compared to the deep water in the
Gulf of Mexico or to some of the areas under moratoria.
92
Q12. Given our need to offset losses to the U.S. Treasury if 0MB or CBO
project that the legislation will negatively impact the treasury,
what suggestions do you have to bring the costs of this legislation
down? Is there anything which can be done to help increase deep
water production without directly affecting the budget?
A12. The targeted incentives supported by Exxon are a good investment
because they would encourage economic growth, create new jobs, and
increase, not decrease, federal revenues. It is important to
remember that the type of incentive supported by Exxon rewards only
successful efforts, that is, the incentive becomes available only if
the project goes forward and there is actual production. A recent
DRI-McGraw Hill study indicates that a $5 per barrel oil equivalent
tax credit for new production in the deep water Gulf of Mexico that
stimulated the development of 2-9 billion oil equivalent barrels of
reserves by 1998 would increase cumulative federal revenues by $6-10
billion.
While additional lease term flexibility would facilitate optimum-
paced development, Exxon believes production incentives are needed
to encourage substantial additional development and exploration
activity in the near term.
93
EJgON COMPANY, U.S.A.
POST OFFICE BOX 61707 • NEW ORLEANS. LOUISIANA 7016M707
October 7, 1993
The Honorable Gene Green
United States House of Representatives
Washington, D. C. 20515-4329
Dear Representative Green:
I appreciated the opportunity to appear before the Subcommittee to discuss the
resource potential in the deeper waters of the Gulf of Mexico and the need for
incentives to stimulate exploration and production activity in these areas. At
the hearing, you asked about the jobs associated with Exxon's Alabaster and Zinc
projects.
The design, fabrication, construction and development drilling for the projects
will require an estimated 1,600 job years of labor. (One job year is equivalent
to one full-time position for one year.) This includes both Exxon and contractor
labor directly related to the projects but does not include indirect jobs created
by the manufacture of materials and the expenditure of wages and salaries by those
directly employed on the projects. There would also be about 20 direct jobs
associated with the ongoing operation of the two fields.
We do not have specific information on the states in which the 1,600 job years
will occur but would expect them to be in locations in which major expenditures
were made. Payment records indicate that Louisiana and Texas are the primary
beneficiaries for drilling and other major contracts. For example, about half of
the expenditures thus far for drilling have gone to contractors in Louisiana and
half to Texas firms.
We have reviewed the major contracts for platform, template and facilities design,
fabrication and construction totaling $155 million and went one step beyond the
primary contractor to determine the geographic location of the major work and
suppliers. The distribution of the $155 million is as follows: Louisiana and
Texas--$67 million each; Pennsylvania--$2 million; Illinois, Georgia and
Oklahoma- -$1 million each; Massachusetts, Florida, California, Wisconsin and
Washington--less than $1 million each; non-U. S. --$14 million (U.K. --$12 million
for the electro-hydraulic control system for Zinc; Japan- -J2 million for seamless,
high strength line pipe). In addition, it is likely that subcontractors purchased
material and services from individuals and firms located in still other states,
but this information is not readily available.
A DIVISION Of EXXON CORPORATION
74-587 0-93-4
94
The Honorable Gene Green
United States House of Representatives
October 7, 1993
Page Two
Attached for your information are answers to questions submitted after the hearing
by Subcommittee Chairman Ortiz and Representative Fields. If you have additional
questions, please contact me or Don Smiley, Vice President of Exxon's Washington
Office.
Sincerely, y
M. E. FLYNN-rf
DIVISION MEAGER
MEF
Attachments
c: w/attachments
The Honorable Jack Fields
The Honorable Solomon P. Ortiz
Mr. D. E. Smiley
95
TESTIMONY OF
RANDY L. NESVOLD
PHILLIPS PETROLEUM COMPANY
BEFORE THE
SUBCOMMITTEE ON OCEANOGRAPHY, GULF OF MEXICO,
AND THE OUTER CONTINENTAL SHELF
COMMITTEE ON MERCHANT MARINE AND FISHERIES
U.S. HOUSE OF REPRESENTATIVES
SEPTEMBER 14, 1993
96
OFFSHORE
ARCTIC EXPLORATION & PRODUCTION CHALLENGES
IN THE
ALASKAN BEAUFORT SEA
By: R. L. Nesvold
September 7, 1993
97
OFFSHORE
ARCTIC EXPLORATION & PRODUCTION CHALLENGES
IN THE ALASKAN BEAUFORT SEA
INTRODUCTION;
Thank you, Mr. Chairman. My name is Randy L. Nesvold. I am the Alaska Area Partnership
Operations Manager for Phillips Petroleum Company's North American Exploration and
Production Division located in Houston, Texas.
My responsibilities include overseeing Phillips' investments and activities in the Prudhoe Bay
and Point Thomson fields on Alaska's North Slope, as well as the recent Sunfish discovery in
the Cook Inlet and the Kuvlum discovery in the Beaufort Sea. I have 12 years of experience
with Phillips and have been assigned to Alaska operations for five years. My educational
background includes a Bachelor of Science Degree in Geological Engineering from the
University of North Dakota and a Master of Petroleum Engineering Degree from the University
of Houston.
Phillips is an integrated oil company that has, for the past 76 years, been located in Bartlesville,
Oklahoma, where it was founded in 1917. We presently employ more than 21,000 people
worldwide and are involved in all aspects of the petroleum business from exploration, production
v\d refining, to transportation, marketing and research. We also are substantially involved in
1
98
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
natural gas production and liquefaction, chemicals production and sales, and we have been active
in other energy areas such as coal, geothermal, nuclear fusion and solar power research. The
company's products and processes are used in 33 countries. Our investments have been limited
primarily to the energy field.
Phillips appreciates the invitation from the Committee to testify on the subject of arctic
exploration and production activities.
BACKGROUND:
Since the late 1960's, over 60 exploratory wells have been successfully drilled on the continental
shelf of the Alaskan Beaufort Sea (See Figure M- 1 ). Unfortunately, due to low oil prices, high
operating costs and the harsh operating conditions of the Beaufort Sea, none of the exploratory
drilling to-date has resulted in discovery of an offshore field that is economic to develop, except
for the shallow water Endicott, Pt. Mclntyre and Niakuk fields located adjacent to Prudhoe Bay.
Currently, all Alaskan North Slope production comes from onshore fields at Prudhoe Bay,
Kuparuk River, Lisburne and Milne Point, and from the shallow water, manmade gravel island
of the Endicott field. Two additional offshore fields; Point Mclntyre and Niakuk, are also
currently being developed. Point Mclntyre is being developed from a shallow water gravel
island and Niakuk is being drilled with long reach wells from a shore-based drill pad. A map
showing the existing North Slope fields is included as Figure M-2.
99
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
To transform the Beaufort Sea from an exploration play to an economical producing trend,
operators will have to overcome environmental, technological and timing challenges presented
by the deeper waters of the Beaufort Sea. Environmental and technological hurdles can most
likely be overcome, but timing is the critical variable. With declining production from existing
North Slope fields, the TransAlaskan Pipeline (TAPS) and related North Slope infrastructure
may become uneconomic to operate as early as 2014. Operators cannot afford to wait for higher
oil prices to make Beaufort Sea exploration attractive. New economically viable, as well as
environmentally sound technologies, must be developed to deal with the harsh arctic climate.
It is crucial this be done soon if new producing fields are to be developed and new production
is to be brought on line before the existing North Slope infrastructure and the TAPS are
abandoned, especially when you consider approximately 25% of our nation's domestic crude oil
production flows through the TAPS line.
ARCTIC ENVIRONMENT:
The arctic environment poses a dual challenge to operators: harsh climate coupled with fragile
ecosystems. During summer months, temperatures average 41 degrees F., but during winter
months, temperatures average 30 degrees F. below zero with maximum low temperatures
dropping to minus 65 degrees F. below zero. Winter operations are also hampered by two
months of total darkness (See Figure E-l).
While the weather conditions provide a formidable challenge, the greatest obstacle to Beaufort
Sea operations is the arctic ice. For nine months of the year, the entire Beaufort Sea is covered
100
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
by a sheet of ice. As shown in Figure E-2, the ice is identified by three zones;
1- LANDFAST ICE - Ice which forms adjacent to the coastline, extending out to water
depths of 50 to 70 feet, where motion is inhibited by the shore. Landfast ice is typically
single-year ice and can reach thicknesses of 6 to 7 feet, but may also contain pressure
ridges with keels as deep as 70 feet.
2. POLAR ICE CAP - This is permanent multiyear ice which circulates clockwise in the
northern Beaufort Sea and central arctic basin. The rotating ice cap is referred to as the
Beaufort Gyre and is shown on Figure E-3. The average ice thickness in the polar ice
cap is only 9 to 12 feet, but large pressure ridges may extend to depths of 150 feet or
more.
3. TRANSITION ZONE - This is the area located between the Polar Ice Cap and Landfast
ice. The transition zone may be tens to thousands of miles wide and generally contains
first year ice, but may also contain concentrations of multiyear ice.
During the month of May, the Landfast ice zones begin to breakup and by July, an ice-free,
open water corridor exists along the coastline. This ice-free zone lasts until new ice begins
forming in October. During the open water season, multiyear ice islands that break away from
the polar ice cap and drift through the open water areas can cause significant operational
101
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
problems. Ranging up to 150 feet thick, these multiyear ice floes cause severe ice loading
problems for permanent structures.
Ice scours, caused by the keels of pressure ridges and multiyear ice floes, can also cause a major
problem for subsea pipelines. Most of the Beaufort Sea research on ice scouring to-date
indicates scours achieve a maximum depth of IS feet. (A conceptual drawing of an ice scour
in relation to subsea pipelines is shown on Figure E-4.)
In addition to the severe arctic climate, operators in the Beaufort Sea must also address unique
environmental issues. For example, the Beaufort Sea is the migratory route for the Bowhead
whales and the Native Eskimo villages of the North Slope still rely on the Bowhead whale for
their subsistence. Operators, in conjunction with the National Marine Fisheries Service
(NMFS), the Minerals Management Service (MMS) and the North Slope Borough, have
monitored whale migration patterns since the late 1970s. The data obtained allows operators to
determine if drilling and seismic operations have an impact on whale migration patterns.
Ultimately, the data acquired provides a basis for structuring drilling and seismic operations in
such a manner as to minimize the impact on the whale migration, and in turn, minimize the
impact on the Eskimo whaling communities.
Environmental compliance can be very costly. A good example of the economic implications
of environmental concerns is the installation of a 650 foot breach in the Endicott causeway.
102
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
Built to alleviate concerns over the impact that the causeway might have on fish migration
patterns, the Endicott owners constructed this 650 foot breach at a cost exceeding $65 million.
EXPLORATION DRILLING TECHNOLOGY:
Current arctic exploration technology is well developed. A fleet of drilling systems is currently
available for arctic exploration. A brief discussion of current arctic exploration technology that
is available to the industry follows:
1 . GRAVEL OR EARTHEN ISLANDS - The first arctic offshore wells were drilled from
gravel islands in 1973. Artificial islands provide a year-round drilling platform and can
be used in water depths of up to 50 feet, but are generally not economical in water
depths greater than 10 feet. (Figure D-l is a picture of Shell's Seal Island well which
was drilled from a gravel island.)
2. CAISSON RETAINED ISLANDS (CRIs) - CRIs were developed to minimize dredging
requirements. The caisson retained island consists of a ring of caissons, stressed together
with cables and filled with sand to form a drilling platform. CRIs have been used in
water depths of up to 70 feet and are capable of operating in up to 100 feet of water.
3. SPRAY ICE ISLANDS (Figure D-2) - Ice islands are created by spraying seawater on
existing ice to create an ice sheet thick enough to ground on the sea bed, forming a stable
103
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
platform for exploration drilling or support activity. Application of ice islands is
currently limited to water depths between 10 to 40 feet within the Landfast ice zones and
drilling time is limited to 105 days. The biggest advantage of ice islands over gravel
islands is the cost of construction. Based on 1985 estimates, ice islands cost $300,000
per foot of water depth versus $1,500,000 per foot of water depth for a gravel island.
4. BOTTOM FOUNDED DRf! -I -INC SYSTEMS - Three bottom founded mobile drilling
systems currently exist for arctic exploration. Bottom founded drilling platforms are
capable of working in water depths of up to 80 feet and allow for year-round drilling.
(Pictures are attached for the Canmar SSDC/Mat (Figure D-3), the Glomar Beaufort Sea
I - CIDS (Figure D-4 and D-5), and the Beaudril Molikpaq (Figure D-6).)
5. DRILL SHD?S (Figure D-7) - Drill ships can operate in water depths ranging from 50
to 1000 feet, but have a very restricted drilling season. Drill ships can only operate in
open water or in partial ice cover when supported by icebreakers. As a result of ice
limitations, drill ships are generally limited to operating from mid-July to early
November. When downtime for severe ice conditions is included, drillships are limited
to an average of 50 to 60 drilling days per year.
6. PURPOSE BUILT FLOATING DRILLING PLATFORMS (Figure D-8) - The
purpose built Beaudril Kulluk floating rig was specifically designed to operate in water
104
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
depths comparable to drillships, but in more severe ice conditions. The Kulluk was
designed to operate year-round in Landfast ice conditions up to 4 to 6 feet thick, but in
the transition ice zones of the Beaufort Sea, the Kulluk is limited to the same drilling
season as drill ships, but with much less downtime due to ice conditions. The Kulluk
is expected to average 100 to 110 drilling days each year.
EXPLORATION COSTS:
Limited public data is available on the cost of exploration wells, but depending on water and
well depths, estimated drilling costs range from 20 to 80 million dollars per well. Shallow water
spray ice islands would be the lowest cost wells, while wells drilled from floating drilling
systems are the most expensive.
PRODUCTION TECHNOLOGY:
Once an offshore field is discovered, options for bringing a field into production are less
defined. Initial developments would likely be based on existing technology, utilizing experience
gained from arctic exploration drilling systems. Currently, the only existing offshore arctic
production is from the man made gravel islands at the Endicott field (See Figure P-l). The 400
million barrel Endicott field began production in October of 1987 and established a peak
production rate of 100,000 barrels of oil per day in 1987. Endicott is located northeast of
Prudhoe Bay and is connected to the mainland by a 5-mile causeway. The total cost to install
the gravel islands and place the field on line was slightly over $1 billion.
8
105
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
Gravel island technology, however, is limited to water depths of 10 feet or less and virtually all
other proposed deep water production schemes are still in the conceptual stage. Several
production platform designs have been evaluated and determined to be feasible with today's
technology. Examples include:
1. STEEL GRAVITY STRUCTURES (Figure P-2) - A steel gravity drilling and
production platform would be constructed using existing construction techniques and dry
dock facilities, and transported to the arctic for final installation. A typical platform
might have a deck area of 125,000 square feet at each of two levels, with a structural
weight of 85,000 tons. The platform could support two drilling rigs and would have a
storage capacity large enough to operate for 270 days without resupply.
2. CONCRETE GRAVITY STRUCTURES (Figure P-3) - Concrete gravity structures
would be fabricated using existing North Sea concrete construction techniques and would
weigh approximately 350,000 tons. Surface areas and capacities would be similar to the
steel gravity platform.
3. CONCRETE MONOCONES (Figure P-4) - The wide base and narrow, single shaft
tower of the concrete monocones are designed to minimize ice loads.
106
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
4. CONCRETE ISLAND STRUCTURES - Concrete island structures are a modification
of Global Marine's CIDS (concrete island drilling system) which has operated in the
arctic. The system consists of a steel base with a concrete tower extending through the
ice zone and steel topsides.
5. STEEL CAISSON STRUCTURES - A steel caisson structure would be constructed of
a circular caisson shell with a sand-filled core. This type of structure has a limited bulk
storage capacity in comparison to a steel or concrete gravity structure.
6. CONCRETE CAISSON RETAINED ISLANDS - A caisson retained island would be
constructed of pre-cast cellular, concrete caisson, which would act as a retaining
structure for a sand/gravel island. Construction costs for this type of structure are less
than for a platform, but the savings are offset by longer installation times and higher
installation costs.
7. PIPELINES - Transportation of oil would almost certainly be via a subsea offshore
pipeline to the Trans Alaskan Pipeline Pump Station #1 at Prudhoe Bay. Although no
subsea pipelines have been installed in the Beaufort Sea, detailed studies have indicated
that installation is feasible using current technology and equipment. Pipelines would be
trenched and buried to depths as required to protect the lines from ice scour. Onshore
10
107
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
pipelines with associated pump stations would be constructed using above ground
supported pipe similar to the existing Prudhoe Bay and TAPS pipelines. In permafrost
zones, pipelines would be insulated to protect the permafrost from the effects of heat
dissipation.
DEVELOPMENT COSTS:
The Alaska Oil and Gas Association (AOGA) has completed extensive research on the costs to
explore and develop offshore fields. Costs for various components of developing a prospect are
as follows:
COMPONENT
Platform Structures
Shallow water (< 50 ft)
Deep Water (> 50 ft)
Processing Facilities
Onshore Supply Base
Well Drilling Cost
Pipelines
Subsea (18 to 24 inches)
Onshore (30 to 36 inches)
COST
$200 to 300 Million/Platform
$350 to 450 Million/Platform
$300 to 600 Million/Facility
$100 to 200 Million
$ 4 to 5 Million/Well
$ 3 to 4.5 Million/Mile
$ 6 to 8 Million/Mile
11
108
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
Depending upon the size of the accumulation, the number of platforms required, the number of
wells required and the distance from the TransAlaskan Pipeline, the cost of development can
vary greatly. Published data on the undeveloped Northstar and Sandpiper fields located in
shallow water near Prudhoe Bay, indicated development costs for these fields range from $860
million to over $1.4 billion. Development of a major deep water field, at greater distances from
Prudhoe Bay, could approach $8 billion or more.
TIMING:
The biggest obstacle facing arctic operators is not the harsh environment or technological
limitations, it's timing. With existing North Slope production declining, it is only a matter of
time before TAPS and the existing Alaskan North Slope infrastructure are forced to be
abandoned due to a lack of economic viability. According to a recent Department of Energy
(DOE) study of proven and probable North Slope production, TAPS is expected to reach its
economic limit as early as 2014. (A forecast of the DOE North Slope Production Forecast is
shown on Figure T-l. )
Although advances in technology or changing economic conditions may extend the life of TAPS
past 2014, this is still a very disturbing statistic. When you consider the fact that current drilling
technology only allows one or possibly two deep water wells to be drilled per year and once a
discovery is made, it will take at least 9 to 10 years to delineate, design, build and install an
12
109
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
offshore production facility, major discoveries will have to be made in the very near future to
make an impact on the economic life of TAPS. (A typical installation schedule is shown on
Figure T-2.)
If a major Meld, either onshore or offshore is not discovered before the end of the decade, it may
be too late to save the TAPS pipeline. The best example of the importance of the TAPS pipeline
and North Slope infrastructure is the lack of development of the Amauligak field in the Canadian
Beaufort Sea. Even with an estimated recoverable reserve of 300 to 400 million barrels with
production potentials of 50,000 barrels of oil per day per well, the field has been uneconomical
to develop due to the lack of a pipeline or an existing infrastructure.
Thank you, Mr. Chairman, for your invitation to allow us to provide the Subcommittee with
information on arctic technology. I would be happy to answer any questions you may have.
13
110
OFFSHORE ARCTIC EXPLORATION AND PRODUCTION CHALLENGES
September 14, 1993
REFERENCES:
1. Brian Watt Associates, Inc., "Feasibility and Costs of Exploration and Production
Systems in OCS Lease Sale 87, Diapir Field, Alaska", AOGA Project 233, February,
1984.
2. Charles Thomas, et al, "Alaska North Slope National Energy Strategy Initiative, Analysis
of Five Undeveloped Fields", U.S. Department of Energy, May, 1993.
3. M. Rojansky, "Arctic Exploration and Production Structures", MTS Journal, Volume 18,
Number 1.
4. B. Danielewicz, "A Short Summary of the Physical Environment of the Beaufort Sea and
Its Effect on Offshore Operations", September, 1983.
5. "Man-made Ice for Construction in the Arctic", Alaskan Update, Volume 4, Number 2,
Spring, 1986.
6. D. Masterson, J. Bruce, R. Sisodiya and W. Maddock, "Beaufort Sea Exploration: Past
and Future", OTC 6530, May, 1991.
7. B. Williams, "Spray Ice Island Technology Advancing in Arctic", O&G Journal,
September 2, 1985.
8. W. Timmermans, "Design, Installation and Operation Described for Beaufort Sea
Pipelines", O&G Journal, May 10, 1982.
9. M. E. Enachescu, "Structural Setting and Validation of Direct Hydrocarbon Indicators
for Amauligak Oil Field, Canadian Beaufort Sea", AAPG, January, 1990.
10. "Arctic Offshore Exploratory Wells", Alaskan Update, Volume 9, Number 4, Winter,
1991/1992.
14
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PHILLIPS PETROLEUM COMPANY
HOUSTON. TEXAS 77251-1967
BOX 1967
NORTH AMERICA
EXPLORATION AND PRODUCTION
BELLAIRE. TEXAS
6330 WEST LOOP SOUTH
PHILLIPS BUILDING
October 11, 1993
VIA TELEFAX: 202/225-1134
Solomon P. Ortiz
Chairman
Subcommittee on Oceanography,
Gulf of Mexico, and the
Outer Continental Shelf
U.S. House of Representatives
Committee on Merchant Marine & Fisheries
Room 1334, Longworth House Office Building
Washington, DC 20515-6230
Dear Chairman Ortiz:
Attached are responses to the list of questions you provided following the hearing on the Outer
Continental Shelf Enhanced Exploration and Deep Water Incentives Act (H.R. 1282) on
Tuesday, September 14, 1993.
Thank you for allowing me the opportunity to participate at the hearing and if you have any
questions, please feel to contact me at 713/669-7465.
Sincerely,
Area Operations Manager
America Exploration & Production
RLN:lss
Attachment
137
HEARING ON OFFSHORE OIL & GAS INCENTIVES
RESPONSES TO QUESTIONS ARE DUE: October 29, 1993
QUESTIONS FOR RANDY NESVOLD:
I. What effect will the proposed incentives have on industry's willingness to develop deep
water or marginal areas? What can be done to stimulate deep water or marginal areas
without legislation?
Any incentive that enhances the potential financial rate of return on a prospect will
stimulate investment. When making an exploration or development decision, an operator
must weigh the potential income a project may generate against the economic risks
associated with the project. Higher risk areas such as the arctic, deep water or other
marginal projects, require much higher potential financial rewards to make the prospect
economically attractive. Any incentives that increase the potential rate of return on an
investment will allow operators to take greater risks and as a result, stimulate exploration
in frontier areas and development of marginal prospects.
However, tax code or royalty relief benefits are probably not sufficient to encourage a
surge in leasing and development of high risk, high cost areas, such as the deep water
prospects in the Gulf of Mexico. Unlike the highly successful, broad-based Section 29
Tax Credit Program, deep water incentives would benefit only a few major players who
can stand the extraordinary risk associated with deep water exploration. For example,
Phillips has no leasehold in greater than 400 meters of water depth and only a very small
interest in water depths greater than 200 meters. In general, only a small group of the
largest oil companies would benefit from incentives limited to deep water. Broad-based
incentives that benefit both large and small companies have the greatest impact on
stimulating development of new oil and gas production. The most effective means of
stimulating investment from all segments of the domestic oil and gas industry, and
ultimately reducing our dependence on foreign oil, is to implement incentives that apply
to any marginal prospect and that are grandfathered to include existing leases.
Additionally, a key consideration companies must take into account is the unpredictability
of incentive programs, especially tax incentives. Congress has a history of legislating
energy incentives only to remove them from the code or allow them to expire a short
time later. This is a significant concern on long lead time projects such as in the arctic
and the deep waters of the Gulf of Mexico. If an incentives program is enacted, there
must be assurances that it could be utilized for the duration of the project unless the need
for the incentive was offset by higher energy prices.
In regard to stimulating investment without additional legislation, the MMS Director
(upon application by the lessee), has the authority to reduce or eliminate royalties to
increase production. This regulation is seldom used because it is poorly understood and
requires clarification. While royalty relief might be of benefit to lessees who already
have deep water projects, it is unlikely such relief will stimulate an aggressive deep water
leasing and drilling program.
138
CHAIRMAN ORTIZ QUESTIONS
Page 2
October 11, 1993
Approximately what percentage of your company's total exploration and development
budget goes to foreign projects? Will this legislation help to bring some of this money
back to the U.S.? Will the development of these deep water areas be accomplished
through the use of U.S. service companies?
In 1992, 63% of our exploration and production budget was spent overseas. This is
compared to only 44% as recent as 1990.
Any legislation that makes U.S. prospects more competitive with overseas prospects will
stimulate increased investment in U.S. oil and gas exploration and development.
However, the proposed legislation will not be sufficient to stimulate a surge in domestic
investment. If the Federal Government wants to encourage increased domestic
investment, it must revisit many of the policies which have been implemented in recent
years, ranging from OCS moratoria to tax policies (such as the Alternative Minimum
Tax).
Any legislation that stimulates investment in domestic oil and gas projects would have
a positive effect on domestic oil and gas service companies.
Does deep water or frontier area drilling and production require any additional
environmental safeguards? If there are any, what are your companies doing to address
these safeguards? Has there been any research completed to address this issue?
Phillips is not currently active in deep water exploration, but in frontier areas such as the
arctic as well as all other areas in which we operate, Phillips plans to conduct all
activities with a minimum impact to the environment.
Currently, Phillips and our partners are conducting baseline environmental surveys in the
Beaufort Sea for use in preparing Environmental Impact Reports.
139
The DeepStar Project
by
J. P. Wilbourn, S. A. Wheeler, C. D. Burton
Texaco, Inc. - Central Offshore Engineering
DeepStar entered its second year of operation in March of 1993. The goal of the program is
the cooperative industry development of technology to facilitate commercial development of
deepwater tracts using subsea technology. DeepStar is a Texaco administered consortium of 15
major operators (Participants) and 30 supplier/vendor organizations (Contributors). Participants
in the Phase 2 program include:
Texaco
Shell
Exxon
Mobil
Conoco
BP
BHP
Chevron
Agip
Elf-Aquitaine
Kerr-McGee
Marathon
Phillips
DeepTech
Arco
DeepStar Concept
Joining together in this industry cooperative effort, progress is being made toward the common
goal of having an economic deepwater production strategy and the necessary technology and
equipment ready for field use by the latter half of this decade. The major technology goals for
DeepStar include evolving a development concept capable of:
• Production in water depths to 6,000 feet;
• Accommodation of a broad range of produced fluid properties and rates from
various reservoir types;
• Subsea satellite production to host platforms up to 60 miles distant (platform
depths 600-800 feet);
• Installation of the subsea facilities in a staged program;
• Minimum maintenance requirements;
• Remote operated vehicle installation and maintenance capability;
• All production operations remotely controlled from the host platform (or
potentially, in early field life, from the drilling vessel).
1
140
The DeepStar concept employs a phased development strategy. It also focuses on a system
approach versus random component designs. The three major stages of the development
approach are as follows:
Exploration/Delineation Drilling
Development Phase 1 consists of prospect appraisal during a field's exploration/
delineation to confirm type and extent of a field's reserves and determine initial
production traits (i.e., probable fluid characteristics such as flow rates, pressures and
composition). Assuming drill-stem tests are encouraging, a decision may be made to
complete these exploration/delineation wells with equipment suitable for longer term
testing using three to five wells as producers during Phase 2.
Evaluation/Early Production
Development Phase 2, or the Evaluation/Early Production phase, will confirm the basic
operability of the production system with relatively low capital commitment. At the
same time, the produced oil and gas will both furnish revenue to help defray Phase 2
costs, and also provide still more (longer-term) reservoir information to augment the
Phase 1 drill-stem tests. During this phase, the operator would produce the three to five
delineation wells to determine if field performance is sufficient to warrant full field
development. If, during Phases 1 or 2, a conclusion is reached that the field is not worth
developing, then an abandonment decision may be made. Under these circumstances,
the objective is to minimize financial loss, assuming production revenue is insufficient
to provide a net profit.
Full Field Development
Phase m development depends on the reservoir size and type. For reservoirs requiring
only 10 to 15 producing wells, a small development concept is appropriate. For 30 to
40 wells, a large development effort would be pursued. Data and experience gained in
earlier phases would be employed in decision-making regarding Phase III development.
One of the critical assumptions for this study was that the field would be offset a significant
distance (25 to 60 miles) from a shallow water host platform. This overall concept is reflected
in the project logo shown in Figure 1. The system schematic for such a subsea tie-back
development is shown in Figure 2. Under the DeepStar concept, initial deepwater subsea
production operations will attempt to use existing platforms as host processing facilities. As
confidence in the deepwater prospect is established, a staged expansion of the subsea facilities
would be initiated as described above. Such an expansion would most likely require the
construction of a new dedicated processing center. Once established, this center would be
capable of handling production from a number of other deepwater prospects within a 60 mile
radius (reference Figure 4). Subsequent developments in the area will be achievable at a
141
reduced cost (estimated at 75% to 80% of original cost per barrel) compared to the first project
which established the processing center. The existence of new deepwater infrastructure will
facilitate the commercial development of small fields (50 MMBOE or less) which would
normally not be considered economically attractive on their own. An opportunity exists here
for the industry to again cooperate and establish joint processing centers that could service an
entire region (reference Figure 3). A joint industry processing center approach could still prove
attractive even if the development concept adopted by several of the venture operators did not
involve subsea production wells.
Phase 1 Technology Studies
The DeepStar team documented and evaluated the capability, cost and availability of basic
components and subsystems that would potentially be required for a remote subsea development
through a series of foundation studies which included:
Multi-phase subsea pumps and subsea separators
Multi-phase and single-phase pipeline systems
Control systems and umbilicals
Chemical injection systems
Templates and manifolds
ROV systems
Diverless/guidelineless modularization
MODU production support operations and safety
The results of specific investigation in these areas provided recommendations as to the best types
or family of components for use in deepwater subsea systems to meet an actual field
development within the next two to five years.
DeepStar Phase 2 Work Program
The work program for 1993-94 of the DeepStar Project is broken into 10 major technology focus
areas: Regulatory, Multiphase Flow & Equipment, Controls Issues, Production Risers, MODU
& Mooring, Flowlines & Umbilicals, Reservoir Performance & Engineering, Manifolds/Trees
& Connections, Produced Fluids, and Drilling & Completion Issues. Work in each focus area
is overseen by a chairman and a technical committee consisting of representatives from each of
the participating companies. The following engineering organizations have been contracted by
the project to perform a number of specialized technology scoping studies.
• Intec Engineering (Program Technical Advisor)
• Aker Omega
• H. O. Mohr Engineering
142
Oceaneering Production Systems
• Sonsub
• Project Associates
One of the unique aspects of DeepStar is that Participants are sharing prior technical research
in an effort to "leap-frog" technology development in these key focus areas and to do so at
minimum cost. The following is a synopsis of progress to date in each of the technology
development areas.
Regulatory Issues
A number of regulatory related barriers exist for development of the deepwater Gulf of Mexico.
Representatives of the DeepStar participant companies have been meeting on a monthly basis
with the Minerals Management Service (MMS) to discuss technology issues and current
regulations in an effort to identify areas where existing regulations are not in step with
technology capabilities. Areas of discussion have included production monitoring & testing,
underwater safety valves, shut-down requests, suspension of production, and subsea
installation/maintenance and repair. Extended well test operations have also been the subject of
discussions and will be the topic of a special report to be issued later this year.
Multiphase Flow & Equipment
Texaco has released the results of an in-house Transportation Options Study to DeepStar
Participants which focused on the transport of multiphase fluids over long distances (up to 60
miles) in extreme water depths (2,000 - 6,000 ft). This work will form the basis for further
joint study work by the DeepStar group on issues related to multiphase transport and the options
open to the industry to add energy to multiphase fluid systems. Many of the major technical
hurdles associated with deepwater production revolve around the challenges that arise from
production in the cold environment associated with deepwater. Examples are: produced fluids
problems such as hydrates/paraffins, and the phase behavior of the fluids being transported.
Initial study work focused on the Gulf of Mexico and showed that 1) reservoir depletion via
natural flow is possible for a period of time. This period of time will depend on reservoir and
fluid properties. The period of time is likely to be in excess of that required for the initial
reservoir evaluation/early production phase of a DeepStar type development, 2) an economical
method of controlling hydrates will be essential for any extended reach development producing
significant quantities of water, 3) hydrates may be controlled either by prevention of hydrate
crystal formation or by controlling agglomeration of the hydrate crystals once formed. The
method of hydrate control will be either via chemical, thermal or mechanical means. The
method of hydrate control used will have a major impact on the type of multiphase flow system,
which can be used and vice versa. This arena of work promises to be one of the areas of key
focus in ongoing DeepStar activities.
143
Control Svstem Issues
The purpose and intent of this work group is to evolve the architecture and direction of control
system developments in the next generation of deepwater control systems. Areas proposed for
study include autonomous control systems, umbilical improvements, basic system architecture,
interface of control systems with subsea pumps & separators. This group has met on several
occasions with representatives of the various vendors and contractors that are acting as
contributors to the DeepStar work. A scope of work has been issued to interested parties
identifying areas of concern, technology requiring further development, and basic questions the
operator community has concerning system capabilities for deepwater deployment.
This work group is being supported by Contributor representatives from FSSL, GEC, Hydril,
Ocean Design, Marston Bentley, Pirelli, Tronic, Multiflex and Koomey.
Deepwater Production Risers
This group is attempting to focus the industry's deepwater riser development efforts on a small
number of promising production riser concepts. These include flexible, rigid/buoyant,
composite, and hybrid approaches. The intent for this year's activity is to compare and perform
a screening analysis of possible options. In the 1994 work program the surviving concepts will
be developed and modelled in greater detail, with a possible progression to wave tank testing
or hardware development. To assist in their analysis work, the committee has a clearly defined
design basis complete with environmental conditions for a variety of Gulf of Mexico potential
deployment sites.
This work group is being supported by Contributor representatives from Coflexip, Wellstream,
Cooper and Hydril.
MODU & Mooring
One of the key aspects of DeepStar will be the ability of existing drilling vessels to
simultaneously drill, moor, and accommodate limited production functions in deepwater. Study
efforts by this group are targeted with addressing issues such as these in addition to exploring
innovative mooring system designs that could dramatically lower the cost of deepwater mooring
systems.
The first part of the effort will concentrate on evaluating the ability of existing drilling
semisubmersibles to moor and drill in water depths between 3000 ft and 6000 ft. Given that this
is economically feasible, the next step is to add minimal process facilities for extended well
testing/early production and finally to produce the field long term. Mooring design criteria for
both extended well testing and long term production are more onerous than for drilling alone and
may require modifying or replacing the existing mooring system. The additional deck load due
to the modified mooring system, deepwater drilling equipment and consumables, production
144
risers, and the process system can easily exceed the capacity of existing drilling vessels. The
vessels, therefore, may require structural upgrades as well to increase the buoyancy and deck
load capacity.
The second part of the study will concentrate on cost reduction measures. These will include
alternate mooring designs such as taut leg systems or DP-assisted mooring, process system
weight reduction, and the effect of downtime due to disconnecting and retrieving the drilling
This work effort is being supported by several Contributors. Reading & Bates, Sonat, and
Sedco-Forex are evaluating vessel and drilling capabilities and determining upgrade requirements
to accommodate increased water depth, deck load and space requirements. Baker-Hughes is
evaluating process system alternatives and Imodco is evaluating FPSO and mooring system
options.
Flowlines & Umbilicals
This work group is charged with identification and development of new, innovative, low cost
methods of flowline/pipeline installation and repair as well as development of alternative
umbilical concepts for ultra deepwater. The group currently is at work on a number of topical
concerns. These include two alternatives for pipeline repair in water depths to 6000 ft, new
(low cost) J-lay techniques and tooling, pigging studies for deepwater systems, and fabrication
of umbilicals from alternative materials.
This work effort is being supported by Contributors including OPI, Heerema, Sonsub, Multiflex,
Pirelli Cable, Stena, Marston Bentley, and Oceaneering.
Reservoir Performance & Engineering
This group's activities are focused on identification and documentation of characteristics of
deepwater reservoirs in the Gulf of Mexico. Characteristics of the deepwater reservoirs,
including their size, productivity, and fluid make-up, will have a direct bearing on the economic
viability of deepwater development. The participants in DeepStar are pooling data collected to
date on deepwater reservoirs in an effort to understand better what design parameters should be
used in planning deepwater developments.
Manifolds. Trees & Connections
The focus of this work group includes all aspects of subsea hardware. This includes preferred
facility arrangements (template vs cluster, satellite, etc.), interface connections, installation
considerations, standardization of equipment/interfaces, manifold configuration, tree layout,
intervention, maintenance, and repair. The group is also attempting to evolve and adopt
standard designs for workover/completion equipment, trees, and manifolds.
145
Efforts within this work group are being assisted by the following Contributors: Heerema,
Cooper, Hydril, National Oilwell, FMC, ABB Vetco, Wellstream, and Coflexip.
Produced Fluid Problems
Second only to reservoir questions, produced fluids problems are seen as the major barrier to
economically viable production from the deepwater Gulf. Of special concern to the Participants
is paraffin production, followed closely by hydrate formation and asphaltene production. The
Participants are evaluating data on these fluids problems in an attempt to identify a direction to
focus expenditure of joint funds. Alternative methods for handling produced fluid problems are
being evaluated including thermal, chemical, and mechanical treatments. As is the case with the
reservoir group, the produced fluids team is collecting data on the different produced fluids
problems that have been encountered in the deepwater Gulf. This data will be used to focus the
group's activities on those aspects of the problem that will most favorably impact the potential
for future development.
One of these areas is the need to develop standardized well test procedures and tools for testing
of exploration wells. The committee has issued a letter of inquiry to a number of manufacturers
in the downhole tool industry with the intent of developing a standard tool for use in taking
downhole fluid samples.
Drilling & Completion Issues
The single largest expenditure for deepwater developments will be well drilling and completion
costs. This activity alone accounts for between 40 and 70% of the cost of deepwater
developments. When viewed in the light of total development costs, this could exceed
$700 million. Cost control and reduction is critical to the effort to make the deepwater Gulf
commercially viable. The Participants are focused on identifying those actions that can be taken
to reduce drilling, completion, and intervention costs.
Participants are being assisted in this area by the following Contributors: Reading & Bates,
Sonat, Sedco-Forex, Profco, CTC International, Baker Hughes, Halliburton, Hunting Oilfield,
Hydril, OSCA, and Bardex.
Conclusions
DeepStar is redefining the way major operators, suppliers, and government agencies can work
together to promote development in technically challenging environments such as the deepwater
Gulf. The program has been operational for almost two years. As can be seen from this report,
many technology issues critical to the progress of deepwater development are being addressed
and innovative development concepts and approaches are being evolved.
146
DeepStar -
Industry Teaming Up To
Develop A Deepwater Concept
Figure 1
147
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Figure 3 - Gulf Of Mexico (600 - 6,000 Ft
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Figure 4 - Central Processing Platform
149
W
James C Prurtl Corporate Communications 1050 i7in street nw
vice President a Division of Texaco Inc Suite 500
Feaera: Government Allaifs WashmgtorrOC 20036
October 12, 1993
The Honorable Solomon P. Ortiz
Chairman
Subcommittee on Oceanography, Gulf of Mexico
and the Outer Continental Shelf
575 Ford House Office Building
Washington, O.C. 20515-6230
Dear Mr. Chairman:
I refer to your September 15, 1993 letter with additional questions
concerning J. Phil Hilbourn's testimony at the September 14, 1993
Subcommittee on Oceanography, Gulf of Mexico & Outer Continental
Shelf hearing on the Outer Continental Shelf Enhanced Exploration
and Deep water Incentives Act (H.R. 1282) .
Enclosed is Texaco' s reply to the questions raised by yourself as
well as those posed by Congressman Jack Fields. If there are
further questions or if you need clarification on the attached,
please advise.
Yours very trul
io^-
JCP:hg
Attachment
150
I. What effect will the proposed incentives have on industry's
willingness to develop deep water or marginal areas? What
can be done to stimulate deep water or marginal areas
without legislation?
a) The royalty relief bill is a positive step, but will
have marginal impact on allowing a project to go
forward. The after tax net present value increase of
the royalty relief is about 10%. It is unlikely that
this increase alone would enhance a project's value
enough to cause many marginal discoveries to be
developed. The tax credit bill by Senator Breaux
(S.403) would more directly influence the decision to
proceed with a marginal discovery. The value with the
appropriate tax credit does increase the economics
enough whereby a marginal project may become
economically attractive and developed.
b) One possibility is to allow gas flaring for an extended
period. Long term production tests allow for a much
more accurate reservoir assessment, thus decreasing the
risk of moving forward with development. Additionally,
in some extreme cases, it may not be economical to lay
a gas pipeline; however, tanker ing the produced liquids
would likely be profitable. Accordingly, tankering as
an alternative means of development should be available
to industry.
II. Approximately what percentage of your company's total
exploration and development budget goes to foreign projects?
Will this legislation help to bring some of this money back
to the U.S.? Will the development of these deep water areas
be accomplished through the use of U.S. service companies?
a) In 1993, Texaco' s budget outlined the following split
between foreign and domestic exploration and development
expenditures :
foreign = 55%
domestic =4 5%
b) The proposed legislation will bring some of the money
back to the U.S. by virtue of some U.S. projects,
especially, the marginal fields, being more economically
attractive when compared to the foreign portfolio of
opportunities .
c) U.S. service companies will certainly have the
opportunity to carry out this additional work provided
they are competitive. The U.S. has begun to lose its
leadership role in the development of offshore
technology due to foreign governments, qua si -government
petroleum societies and national oil companies'
sponsorship of this activity. However, as we have seen
151
in the past,, if there is an application the
entrepreneurship of the U.S. service companies will
provide the resources and brain power to develop the
tools and equipment needed. -
III. Does deep water or frontier area drilling and production
require any additional environmental safeguards? If there
are any, what are your companies doing to address these
safeguards? Has there been any research completed to
address this issue?
a) The existing regulatory controls for the offshore
industry are more than adequate to protect the
environment .
b) Texaco has its own worldwide E&P Environmental Practices
for exploration and production operations that are
designed to protect the environment in all operating
conditions.
c) Both DOE and API have conducted field research around
offshore drilling and production facilities. These
studies have shown that there is minimal impact from
properly conducted operations in shallow waters where
effluents may not be as well dispersed as in deep water.
Dispersion studies have verified these conclusions.
d) In 1990 Texaco established an Environmental, Health and
Safety Division in order to strengthen its record of
performance in the broad array of environmental, health,
and safety matters. Paramount in the EHS Division is
the ongoing initiative to strengthen our ability to
respond to oil spills. As part of this program, Texaco
conducts emergency drills in each of its U.S. East
Coast, West Coast and Gulf Coast regions. These
exercises provide much needed experience for our
employees and contractors on how to control and mitigate
the effects of an oil spill.
e) Texaco has also joined with other oil companies to
improve response to oil spills by its participation in
the Marine Spill Response Corporation (MSRC) . The
MSRC assembles oil spill response experts and
stockpiles against the possibility of future
spills. In addition, a formal agreement among API
members called "Petro-Assist" is in place whereby
each member volunteers to provide resources to other
members in time of crisis.
10 Yr. Ava.
1992-1983
15 Yr. Ava.
1992-1978
40%
60%
39%
61%
152
How much of your current exploration budget is spent in the
U.S.?
In 1993, Texaco budget projects the following split between
international and domestic exploration and development
expenditures :
1993
Int's 55%
Domestic 45%
2 . How does that compare with ten or fifteen years ago?
See Answer to #1 Above.
3 . If other incentives such as tax credits were offered would
that change your decision to go abroad with your exploration
budgets?
Senator Breaux's tax credit proposal significantly increases
the value of a discovery. Small finds that would be
otherwise uneconomic may be developed with a reasonable rate
of return. The Gulf of Mexico (GOM) is one of the most
prolific hydrocarbon provinces in the world. Finding
accumulations in the deep water is not nearly as difficult
as finding economic accumulations. A tax credit would make
more discoveries economic, and should lead to increased
exploration and development activity in the GOM.
Are there any areas other than the Gulf where some type of
royalty relief should be offered?
The Bureau of Land Management has a program of reduced
royalty rates for marginal oil wells located on onshore
federal lands. This program should be continued and
expanded to include marginal gas wells. A program for
marginal oil and gas properties and enhanced oil recovery
projects located on Minerals Management Service leases
should be considered.
5. If some type of incentive is not available, how cost
effective is it to explore Arctic areas?
The Arctic areas present their own set of technological
challenges quite differently from the deep water GOM. The
Arctic area is not economical without significant
accumulations near the existing infrastructure and
transportation network.
153
6. Obviously the cost of technology to develop deep water areas
is high. What other technologies such as air quality
controls add significant costs to a development project and
should be considered for royalty relief?
Other technologies that have been identified as adding costs
to a development project in deep water:
a) Composite materials to reduce weight and increase
strength in:
1) Risers, production and drilling
2) Mooring Systems
3) Flowlines, Pipelines, umbillicals
b) Power generation with fuel oils
c) Submersible electric motors, electrical (set)
connections
d) Multi-phase meters and pumps for submersion service
e) New chemicals for hydrate and paraffin inhibition
purposes
f) Produced water treatment processes and hardware to
reduce weight and space
g) More effective oil and gas treatment processes and
hardware to reduce size and weight
h) More effective instrumentation and control technology
and monitoring hardware
7. What other incentives should be considered to make deep
water development cost effective?
One possibility is to allow gas flaring for an extended
period. Long term production tests allow for a much more
accurate reservoir description, thus decreasing the risk of
moving forward with development. Additionally, in some
extreme cases it may not be profitable or feasible to lay a
gas pipeline; however, tankering the produced liquids would
likely be profitable.
8. Would it influence your lease purchasing decision to know at
the lease sale whether a lease were eligible for royalty
relief?
Meaningfully royalty relief would cause lessees to be more
aggressive in trying to identify viable prospects. However,
the attractiveness of a lease would depend solely on the
prospect's potential.
154
9. In your opinion, does the Secretary have the ability to
reduce or suspend royalties and is that authority used? How
could that authority be expanded to make it more available?
We believe this question is best directed to the Solicitor
of the Department of Interior. However, if it is deemed
that he has this authority, as we believe he does, we
believe it should be delegated to the Regional Director.
10. Would it be more effective if the Secretary could grant
royalty suspension or relief before production began?
Certainly, prior granting of royalty relief is required to
facilitate planning and decision making. One cannot
undertake any reasonable economic evaluation without knowing
what the royalty burdens on a particular prospect will be.
11. If moratoria continue off the Pacific and Atlantic coasts,
what areas are there left for exploration?
Deep water GOM or foreign opportunities which offer the
appropriate rate of return for the assumed risk.
12. Given our need to offset losses to the U.S. Treasury if OMB
or CBO project that the legislation will negatively impact
the treasury, what suggestions do you have to bring the
costs of this legislation down? Is there anything which can
be done to help increase deep water production without
directly affecting the budget?
Texaco is supportive of an "Environmental Equalization Fee"
on imported gasoline and blendstock. Revenues from one such
proposal presented to the Ways and Means Committee have been
calculated at $1.9 billion over five years, sufficient to
provide for a targeted program of domestic drilling
incentives supported by both majors and independents.
155
A Brief Review of Technology
and Research
Prepared for the
Hearing on Proposed Legislation to Provide Incentives
to Explore, Develop and Produce Domestic Natural Gas
and Oil Resources in Frontier and Deep Water Areas of
the Outer Continental Shelf
by
Dr. Hans C. Juvkam-Wold*
Petroleum Engineering Department
Texas A&M University
College Station, Texas
September 6, 1993
1. Deep Water Outer Continental Shelf
2. Arctic Offshore
Brief Resume Attached
156
Below are two separate discussions, the first one dealing with the outer continental shelf of the
United States, and the second with the Arctic offshore, north of the Alaskan mainland.
Each discussion is split into two parts: Part (a) discusses the kind of exploration drilling that is
performed to locate hydrocarbons, and part (b) discusses the actual production of such
hydrocarbons.
1. Deep Water Outer Continental Shelf
(a) Exploration Drilling
In water depths to about 300 ft, exploration wells can be drilled from jackup rigs
that stand on the ocean floor. In deeper waters, essentially all exploration wells
are drilled from floating drilling vessels. There are two distinct types,
semisubmersibles and drillships.
The semisubmersible is a very stable floating drilling vessel designed to
operate in rough weather conditions. It is usually anchored with 6-12 mooring
lines to maintain its position over the well that is being drilled. These units
currently can drill in water depths up to about 4,000 ft.
The drillship is a ship-like vessel specifically designed for floating drilling.
Drillships can currently be used in water depths up to about 7,500 ft. In water
depths up to 4,600 ft, the drillship can also be moored, but beyond about 4,000 ft
the vessel is usually dynamically positioned; i.e., it is kept in place above the
wellhead by numerous thrustors (propellers) strategically located around the hull
of the vessel.
Research currently is being conducted on finding better and safer ways to drill
deepwater wells. Computer models of well drilling and well control techniques
are being developed to increase our understanding of the variables affecting well
control problems and to aid in the training of drilling personnel by simulating
troublesome situations. For example, when abnormally high downhole pressures
are encountered in deepwater wells, the control of the well becomes more
complicated, so extensive education and training under non-threatening situations
157
is essential for maintaining a safe operation. Some computer models make use of
artificial intelligence and expert systems.
Research is also being conducted on the formation of hydrates (ice containing gas
molecules in its structure) to understand how hydrates are formed, how they can
affect the drilling operation by plugging lines and valves, and how problems
resulting from hydrate formation can be handled.
(b) Hydrocarbon Production
Near shore hydrocarbons can be produced through wells that are directionally
(non-vertically) drilled from onshore locations. The bottoms of such wells can
typically reach about two miles offshore. In a few cases offshore wells have
reached as much as three miles horizontally away from the surface location. One
recent well in the North Sea had a total horizontal reach of about four miles.
Production in Water Depths to 1,000 Ft
In waters to depths of 1,000 ft, hydrocarbons are generally produced through
wells drilled from steel platforms that stand on the ocean floor and are attached
to the bottom by steel pilings that penetrate several hundred feet into the ocean
floor. The largest bottom-supported platform in the world stands in 1,353 ft of
water. Production wells are usually drilled from the platform after platform
installation. Extended reach technology is used and wells typically are drilled to
bottom-hole locations one or two miles horizontally removed from the platform.
On such platforms the oil is separated from the co-produced gas and water, and is
transported to shore via pipeline. Gas may be re-injected or transported to shore
in a separate pipeline. When feasible, the pipelines tie into other pipelines and do
not have to go all the way to shore.
Bottom-supported platforms also may be made from steel-reinforced concrete.
These are often used in the North Sea where the sea floor can better support such
structures. This is not die case in the Gulf of Mexico because the soils are not as
strong.
74-587 0-93-6
158
Production in Water Depths beyond 1,000 ft
The cost of conventional steel-jacket bottom-supported platforms increases very
rapidly with increasing water depth, so in waters beyond 1,000 ft other
alternatives are considered. These include compliant towers, tension leg platforms
and floating production systems. Another option is subsea well completions with
subsea production lines to platforms positioned in shallower waters.
Drilling Platforms
Compliant towers are partially bottom-supported platforms that can have built-
in buoyancy chambers so that not all the weight is supported on the bottom.
Generally these structures are much slimmer and more flexible than the
conventional bottom-supported platforms; such structures have been designed to
be used in water depths to about 3,000 ft.
Tension Leg Platforms are floating production structures that are tied to the
seafloor by vertical steel pipes or "tendons." These structures experience very
little vertical motion but can move somewhat horizontally. One such structure is
about to be installed at 2,860 ft in the Gulf of Mexico. In the case of this platform
the wells were predrilled before installation of the platform itself; this reduces
the time between installation of the platform and production. Researchers believe
that tension leg platforms eventually will be used in water depths to 10,000 ft.
Floating Production Platforms are usually anchored to the sea floor with
multiple mooring lines. Such platforms may be used for early production
systems, allowing a project to commence production, perhaps directly into a
moored tanker, while the permanent production facilities are being installed.
Floating platforms also may be used on a longer term basis for production from
smaller reservoirs, where the cost of permanent facilities cannot be justified. An
advantage of floating platforms is that they can fairly easily be moved to another
location when they are no longer required. The water depth limit for current
designs is estimated to be around 6,000 ft.
Subsea Completions
Subsea Completions refers to wells drilled from floating drilling units. These
wells are completed with production wellheads at the sea floor. They are then
159
connected by subsea production lines to a nearby subsea collection point and from
there to a platform. These multiphase pipelines (producing oil, gas and water
together) can be several miles, perhaps tens of miles, away from the production
platform. For reservoirs that are too small to support the cost of their own
production platforms, subsea completions may be the answer. This is feasible if
the production lines can reach an existing platform, or a platform specifically
designed to receive production from a number of small, scattered reservoirs or
wells. With the use of subsea completions, the wells themselves may be located in
very deep water (perhaps 7,000 ft or more), whereas the production platform
could be in much shallower water.
Subsea completions have been successfully used to depths of 2,562 ft offshore
Brazil, and designs exist that can go to about 5,900 ft. At least 170 subsea
completions have been installed offshore Brazil, with production going to fixed
platforms in shallower water or to floating platforms.
The Texaco Deep Star Project will utilize subsea completions with very long
production lines, up to 60 miles, to existing or new platforms that will be in 800
ft of water or less. Researchers expect this concept to make production possible
from many small and medium-sized reservoirs in the Gulf of Mexico out to a
water depth of about 6,000 ft. Participants in this joint industry project include
most of the major oil companies in the U.S., many independents, and a variety of
service companies and equipment suppliers.
Research in the Outer Continental Shelf
Research related to production from the deep water outer continental shelf is
geared mostly towards making it financially possible to produce from reservoirs
that are too small to support the high cost of separate production platforms with
associated pipelines to shore.
One approach is the one mentioned above, to use subsea completions and produce
to remote platforms located in relatively shallow waters. In many cases, the flow
in these long lines will require pressure boosters in the form of subsea multiphase
pumps. Before such pumps are available and reliable, a substantial amount of
R&D will be required.
160
Cold subsea temperatures will in some cases result in the formation of hydrates
and/or paraffin and asphaltene deposits. Better technology to prevent or remove
such solids will be required. Subsea separators may be required to remove the
water and thereby avoid formation of hydrates.
Another approach to making smaller reservoirs economical is to reduce the cost
of deep water platforms such as tension leg platforms. These platforms are
generally designed to be constructed from steel or concrete. A substantial
research effort is underway to construct the platforms, and also the tendons, from
composite materials, such as fiberglass and graphite, combined with appropriate
epoxies. This approach has the potential to reduce the weight significantly,
possibly by a factor of four, and this in turn should reduce the overall cost.
Different platform geometries are being evaluated in terms of the hydrodynamic
and other forces acting on the structures. Extensive computer modeling is
contributing to these designs.
Another exciting new technology being used extensively is the evaluation of 2-
dimensional and 3-dimensional seismic data to find hydrocarbon reservoirs. With
very extensive — and expensive — computer modeling and data processing, it is
now possible to recognize petroleum reservoirs under 2,000-ft-thick layers of
salt. Exxon has been demonstrated that it is possible to drill through these thick
salt layers into the sub-salt reservoirs. Further application of this technology
could significantly increase the reserves in the deepwater outer continental shelf.
Extended Reach and Horizontal Drilling
Research currently is being conducted in the areas of extended reach and
horizontal drilling. Extended reach research may lead to longer reach from land
and from platforms, and horizontal drilling may lead to higher production rates
per well. Horizontal sections can now be drilled as long as one mile without much
difficulty; the world record currently stands at about one and one -half miles. The
research deals with the modeling and prediction of torque, drag, cuttings
transport and buckling of tubulars. The results have general applicability
wherever drilling is taking place.
161
Drilling for hydrocarbons is a relatively safe and well-understood process, but
blowouts — flowing hydrocarbons to the surface out of control — still happen on
occasion. More research should be done in this area to further improve safety.
2. Arctic Offshore
What makes the Arctic offshore unique in petroleum development is the presence
of moving ice. This results in very high costs.
(a) Exploration Drilling
Most exploration drilling in waters to depths of about 50 ft has been
accomplished from man-made gravel islands. At one time it was estimated that a
gravel island would cost about one million dollars per ft of water depth. There
are many exceptions to this "rule," but gravel islands are very expensive and
essentially non-reusable. Also, in deeper waters the cost is much higher than the
linear rule above suggests.
One approach to cutting costs while maintaining safety is to make the islands
from man-made ice. Experiments were made with this approach in the mid-
1980's. Following these experiments, at least two exploration wells were drilled
successfully from ice islands that cost about one quarter as much as gravel islands
in comparable water depths.
Another approach is to make the islands from steel or concrete and ballast them
down with gravel and/or water. These islands have the advantage of being
portable and therefore reusable. The water depth capability of these units can be
extended by placing a gravel berm or a steel mat under the drilling structure.
Drilling from these structures is usually accomplished in winter, when the ocean
is frozen over. During the winter the sea-ice typically grows to about 5 to 7 ft in
thickness. Ice ridges caused by interaction between ice sheets, can be several times
as thick. The ice moves around and can apply high forces to the drilling
structures. In shallow waters (less than 50 ft), transportation to the rig is usually
over grounded or floating ice roads during most of the winter.
162
In water depths of 100 ft or more, floating drilling vessels are used, either
drillships or specially designed semisubmersibles. Drilling from floaters
generally takes place during the two or three summer months of relatively ice-
free waters. An existing Arctic semisubmersible is designed to extend the
"summer" drilling season to about six months, with the help of ice breakers and
ice-breaking supply ships.
(b) Hydrocarbon Production
In shallow waters, a few feet deep, production is currently accomplished from
gravel causeways or fill, extending the shore out into the Arctic Ocean.
In spite of existing hydrocarbon discoveries, there is no current production in
waters deeper than a few feet. In water depths to about 100 ft, we believe that
production can be made to gravel islands or transportable steel/concrete
structures like the ones discussed above for drilling exploration wells. Production
wells could be drilled from enlarged versions of these islands or structures.
Bringing the product ashore is more complicated.
Transportation of the crude could be accomplished via buried pipeline to shore,
or by icebreaker tankers, or possibly through underground tunnels in the
permafrost. All of these options are very expensive. Much more research is
needed in this area.
In water depths beyond 100 ft, production structures have to be very large,
strong and heavy, to resist the very high forces from moving ice. A number of
such structures have been designed, but none of these have been built. In some
areas, weak soils further complicate the designs.
Here again transportation of hydrocarbons to shore can be via buried pipeline or
icebreaker tankers. Clearly, the costs will be very high.
Research related to production from the Arctic offshore has been going on for
some time. During the 1980's a number of joint industry studies were conducted
to determine when the ice freezes up in the fall, when it breaks up in the spring,
and how it behaves in between. Several ice movement, ice thickness and ice
163
strength studies were made. The purpose of these studies was to determine what
ice forces the drilling and production structures would need to be able to
withstand.
Some studies of this type are continuing, to determine how best to design the
structures so that the ice breaks before the structures do.
Large ice chunks periodically break off from Ellesmere Island in the Canadian
Arctic and float around in the Arctic Ocean for years and even decades. These
floating ice islands or flowbergs can be several miles long and wide and present
quite a hazard to structures, possibly including buried offshore pipelines. Studies
are underway to monitor the movements of some of these flowbergs. Such
monitoring is now being conducted via satellites.
Proprietary Research
In addition to the research and studies discussed above, there is no doubt that
much proprietary research is going on within research laboratories. This
research is not generally known and available, and much of it is likely to be site
specific.
Because of the high cost of studies in the Arctic and the deep water outer
continental shelf, such studies are usually carried out in joint industry projects.
We will continue to see more of this, and also even more cooperation in the joint
use of production and transportation facilities.
164
RESUME
Name: Hans C. Juvkam-Wold
Citizenship: U.S.
Education: SB. in Mechanical Engineering, MIT, 1966
S.M. in Mechanical Engineering, MIT, 1967
Sc.D. in Mechanical Engineering, MIT, 1969
Experience:
Educational Institutions
Professor of Petroleum Engineering and Holder of the John Edgar Holt Chair
in Petroleum Engineering, Texas A&M University, September 1 985 to Present
Assistant Department Head, Petroleum Engineering Department, 1993 to Present
10
Industrial:
Staff Advisor - Frontier Projects. Guff Oil Exploration & Production Co, Alaska, 1983-1985
Manager Technical Services, Gulf Mineral Resources Co., 1979-1983
Director Project Evaluation, Gulf Mineral Resources Co., 1978-1979
Director Special Projects, Gulf Mineral Resources Co., 1976-1978
Supervisor Production Engineering, Gulf Research & Development Co., 1973-1975
Senior Research Engineer, Drilling, Gulf Research & Development Co., 1972-1973
Research Engineer, Gulf Research & Development Co., 1969-1972
Production Foreman, Mene Grande Oil Co., Venezuela, 1961-1963
Construction Foreman, Constructors Arturo Ceballos, Venezuela, 1959-1961
Well Tester, Laborer, Interpreter, Mene Grande Oil Co., Venezuela, 1961-1963
Consulting:
National Institute of Standards and Technology
Frontier and Offshore Technology Co.
Western Irrigation Supply House
Professional Licenses: Registered Professional Engineer, State of Texas
Society Participation:
Society of Petroleum Engineers
• Member, Education & Professionalism Committee, 1988-1991
•Chairman, E&P Committee, 1989-1990
• Member, Education & Accreditation Committee, 1990-1993
Institute of Shaft Drilling Technology
Honors:
Member of Tau Beta Pi, Pi Tau Sigma, Sigma Xi and Pi Epsilon Tau
Recipient of the Tenneco Teaching Award, 1990
Recipient of the Association of Former Students of Texas A&M University
Distinguished Teaching Award, 1992
Publications:
Journal and Conference Papers - 25
U.S. Patents - 3
Septembers, 1993
165
TEXAS A&M UNIVERSITY
DEPARTMENT OF PETROLEUM ENGINEERING
COLLEGE STATION TEXAS 77843-3116
409/845-2241 FAX: 409/845-1307
October 11, 1993
Mr. Solomon P. Ortiz
Chairman, Subcommittee on Oceanography,
Gulf of Mexico, and the Outer Continental Shelf
Room 1334 Longworth House Office Building
Washington, DC 20515-6230
Dear Mr. Ortiz:
I am happy to send you my reply to your question:
"Does deep water or frontier area drilling and production require any
additional environmental safeguards? If there are any, what are your
companies doing to address these safeguards? Has there been any research
completed to address this issue?"
The major environmental danger lies in not developing the frontier
areas. For every barrel of oil that is not produced in the United States one
barrel of oil must be imported. This usually involves the use of tankers, which
represent the largest source of pollution in our waters.
According to the National Academy of Sciences, offshore oil production
accounts for less than two percent of all the oil in the world's seas and oceans,
whereas marine transportation accounts for almost 46 percent. The
Congressional Research Service in a 1990 report stated, "... The volume of
oil spilled in U.S. waters will likely increase as tankered imported oil is
substituted for OCS production."
A major hazard in drilling is blowouts. The U. S. drilling industry has an
excellent drilling record, but blowouts still do occur, and more needs to be
done to further reduce the risk of blowouts. (A blowout is an uncontrolled
flow of formation fluids from a wellbore). According to the Minerals
Management Service, from 1971 to 1991, 87 blowouts occurred during
COLLEGE OF ENGINEERING TEACHING • RESEARCH . EXTENSION
166
drilling operations on the Outer Continental Shelf. This corresponds to one
blowout for each 256 wells drilled in search of hydrocarbons. It was also
pointed out that most of the blowouts were of short duration, and since most
of them were blowing gas, and not oil, there was relatively little pollution
asociated with these blowouts..
Much research has been conducted on well control to prevent blowouts.
Research is currently underway at several universities and research labs to
develop computer models that can perform simulated blowouts, thereby
helping us to learn more about this problem. Such models can be used to train
drilling personnel to respond correctly when the danger signals of a possible
blowout first occur. However, more research needs to be done in this area,
especially regarding well control in very deep waters, but also in developing a
better understanding of shallow gas blowouts.
Other areas of concern regarding frontier drilling and production include the
effect of mud slides and loop currents on the outer continental shelf, and
ice movements in the arctic. The impact of these natural phenomena on
offshore platforms, wells and pipelines must be fully understood before
facilities are installed. Both general and site specific evaluations are necessary,
but this is well understood by the oil companies, and some such studies have
been completed. It is the high cost of such studies and the resulting very high
cost of installations that frequently make oil development in frontier areas
uneconomic at current hydrocarbon prices. Tax or royalty relief would help
to make some prospects economical.
By far the most effective way to spur U.S. production, reduce consumption
and reduce oil imports is an import fee on all imported oil. This would have
the beneficial effects of reducing pollution in the oceans and in the
atmosphere, reducing our balance of trade deficit, and substantially reducing
the federal budget deficit.
2a~
Hans C. Juv&un-Wold
Holt Professor of Petroleum Engineering
167
Testimony before the
U.S. House of Representatives
Committee on Merchant Marine and Fisheries
Subcommittee on Oceanography, Gulf of Mexico,
and the Outer Continental Shelf
Tuesday, September 14, 1993
2:00 P.M.
1334 Longworth House Office Building
Hearing on Proposed Legislation to Provide Incentives
to Explore, Develop, and Produce Natural Gas and Oil Resources
on Certain Areas of The Outer Continental Shelf
Panel II
Mr. Jim 0' Sullivan
Manager, Brown & Root Seaflo
Summary
Gulf of Mexico oil producing reservoirs in deep water will
have to perform better than fields on th«= shallower shelf in order
to be economically viable. Development wells will have to produce
at higher rates, and will have to drain larger reservoir volumes
per well. With such improvements in reservoir performance, field
developments in the 75 to 150 million barrel range can yield a rate
of return of 15% before consideration of U.S. Federal Income Tax.
However, individual operators may place a variety of other risk
adjustments impacting the rate of return on these developments,
especially in light of lower risk alternatives.
In the short term, technology developments will not greatly
reduce the cost of deepwater developments. Existing technologies
can be extended to develop fields in 5,000 to 6,000 foot water
depths in the Gulf of Mexico. Current technology developments are
addressing areas affecting approximately 25% of costs that make-up
the total installed cost for a deepwater project. The success of
these efforts in the short term can reasonably reduce these costs
by another 25%.
168
Introduction
The following comments result from an in-house Brown & Root
examination of deepwater development prospects (i.e., beyond diver
depth of 1,000 ft). Specifically, we wanted to know: what drove
development economics in general; what drove them specifically in
the Gulf of Mexico (GOM) ; and what areas of capital cost held the
most potential for improving development economics. The
examination was done separately for oil and gas developments, with
only the oil case presented here. We hope the discussion will
serve as a useful framework for viewing development economics and
technology trends.
The analysis made use of the SEAPLAN computer program. This
program is an expert system that can identify, conceptually define,
and economically compare technically feasible approaches for
developing offshore oil & gas fields. The code logic and cost
database are updated twice a year as part of the maintenance
program for the 16 international oil operators who have licensed
the program. We feel the program's sizing logic and cost data base
create system descriptions representative of developments being
planned in the deepwater GOM.
Economic Drivers
This section addresses what operators can afford to pay for
deepwater GOM developments. Areas considered are: what economic
criteria GOM operators use to decide whether to proceed with
projects; and, what value operators put on hydrocarbon reserve
estimates in the ground.
The discussion begins with an examination of the return on
operating capital of 17 GOM operators representing a range of
company sizes. The return on operating capital is based on
financial data from each company's annual reports over the last
five years. We used this measure as a reasonable estimate of each
company's project "hurdle rate," that is, the rate of return on
investment reguired for project approval.
There are many definitions of return on operating capital. We
defined the sources of capital as operating revenue minus point-of-
sale excise tax (e.g., gasoline tax), plus sale of assets. Uses of
capital included both capital and operating expenditures for
upstream and downstream operations in both foreign and domestic
operations (i.e., all alternative operating uses of capital).
Federal income taxes were not included as uses of capital, nor were
depreciation expenses, corporate overheads, or financial costs
(i.e., interest or dividends).
The summarized results, shown in Figure 1, indicate an average
rate of return for the industry of approximately 16%. This agrees
with the often stated internal project hurdle rate of 15% before
income tax. In the following present value analyses we used 15%
before tax as the discount rate.
169
Next, we estimated the capital cost an operator can afford to
spend to develop a field. This is expressed as the present value
of the reserves in the ground per barrel of recoverable reserves,
and is equal to the discounted sum of the fraction of recoverable
reserves produced per year, multiplied times the price of oil
forecasted that year. In the following discussion, this value is
referred to as the present value of reserves.
For this analysis, a price of $20/B (i.e., $20 per barrel of
produced oil) was forecasted to remain constant into the future
(i.e., no price escalation). We assumed that gas separated from
produced oil was reinjected to help maintain initial production
rates and to eliminate the capital cost of gas pipelines. Also, an
average operating expense of $3/B was considered, though this will
be a function of technology used, pipeline tariffs, etc.
The present value of reserves is a function of initial
production rate, reserve size, rate at which wells are brought on-
stream, price forecast, and discount rate. The last two variables
have been set for the current study. The following discussion
examines the influence of the other three variables.
Reserve size has a linear relationship with the present value
of reserves. It is not greatly influenced by the number of wells
used to develop the field. This is demonstrated in Figure ?. which
shows the present value of reserves on the vertical axis,
recoverable reserves on the horizontal axis and a set of curves
representing a range of reserves per well (i.e., amount of oil
eventually produced by each production well) . For the same range
of reserves per well, smaller fields are produced faster and
therefore have a higher present value per barrel of recoverable
reserves. Also, smaller fields show a diminishing return for
increasing well count because the life of an individual well
decreases to the point where the production from initial wells
drilled starts to decline before the last wells are drilled.
A similar result is seen in Figure 3 where the initial
production rate is varied for a fixed reserve size. Note that the
set of curves depicting reserves per well show the same diminishing
return as more wells are added to a reserve of a given size.
There are several points to make regarding these graphs.
First, a good performing GOM well on the shelf can produce 2,000
B/D (i.e., barrels of oil produced per day) and drain around 3
MMB/W (millions of barrels per producing well) . Geologists are
expecting reservoirs in deep water to have thicker net pay zones.
This should mean more drainage volume per well and higher
production rates than encountered on the shelf. A rate of 3,000 B/D
is considered in the following analyses, giving a development cost
constraint of $6.50/B (Figure 3). Next, though reserve size per
well is not a very important factor in the present value of
reserves, it becomes important when the costs are considered for
drilling and processing the production from those wells. Finally,
because of the general assumptions used, this present value
analysis is applicable to other areas of the world, not just the GOM.
170
Figure 4 shows the effect of discount rate on the present
value of reserves. An important point to recall from Figure 1 is
that certain operators are enjoying returns on operating capital
higher than 15%. Such alternative investment opportunities may
drive those operators away from a GOM development while other
operators would find the same development very attractive.
A final factor influencing the present value of reserves in
the ground is the rate at which you drill and complete (D&C) wells.
Figure 5 shows the effect of D&C times. Note the above analysis
used 6 wells per year. The rate of well D&C is a function of well
depth (i.e., reservoir depth and well spacing), number of rigs
operating and learning curve effects. Deepwater GOM fields tend to
be have deep reservoirs, typically around 10,000 ft to 15,000 ft
below the sea surface. Initial development wells can take 3 months
to D&C (i.e., 4 per year). However recent deepwater drilling
results have shown the effect of the learning curve wherein D&C
times on the final wells dropped by a factor of 2.
A rate of 2 months per well (i.e., 6 per year) was assumed as
an indicative value. A single rig was assumed for the development
and comparison of capital costs.
Development Costs
This section examines representative Total Installed Costs
(TIC's) for deepwater GOM developments. The SEAPLAN computer
program was used to generate TIC estimates for new installation
production systems that differed by numbers of wells, water depth
and distance from existing infrastructure such as pipelines that
can accept a sales quality crude oil.
SEAPLAN was used to select the most economical technology for
each case from among a range of available technologies:
Conventional Fixed Platform (CFP) ; Compliant Piled Tower (CPT) ;
Tension Leg Platform (TLP) ; and a Floating Production System (FPS) .
Floating Production, Storage and Offloading (FPSO) systems were not
considered since they introduce shuttle tanker transportation
rather than a pipeline; such an analysis can be done as a follow-on
study. Also, newer, novel approaches such as spar buoy systems
have not yet been considered, but could be later.
A new-build semisubmersible vessel was considered for the FPS
cases. Operators have, and are currently, converting semi-
submersible drilling units into FPS vessels. There are two reasons
for the new-build choice for this analysis: the aging of the
existing fleet of available vessels, and the utilization of the
younger vessels as drilling units. The majority of vessels in the
existing semisubmersible drilling fleet are older than their
original design life. Conversion to a deepwater FPS will be very
expensive, with the expense increasing each year. Also, the newer
rigs are in demand for drilling and few new rigs are being built
because current day rates do not support new construction. The
window of opportunity for conversion to FPS's is closing.
171
The resulting Total Installed Costs (TIC's), shown in Figure
6, form a relatively consistent set of curves for different numbers
of wells over a range of water depths and production system
technologies. Since each well is initially producing 3,000 B/D,
the capacity of the process facilities is constant for each assumed
well count. One water injection well is assumed for each four
producing wells, and one gas injection well is assumed for each 10
producing wells. Note that Figure 6 shows only the producing
wells.
Different operators have different risk perceptions regarding
deepwater GOM developments. They may impose risk adjustments such
as cost multipliers for specific cost categories (e.g., 20%
contingency for offshore construction) , or require a higher overall
project hurdle rate (i.e., same effect as a single cost multiplier
over all cost categories) . The risk adjustment factors would
probably increase with increasing water depth. For the purposes of
this study, no risk contingencies were considered.
The type of production system technology changed over the
range of water depths considered. Figure 7 presents a general
indication of the applicable water depth and well count ranges for
each technology as determined in the SEAPLAN parametric study.
Note that the demarcation lines shown indicate where competing
technologies have comparable economies. The actual overlap of
comparability may extend beyond just a single line. Also, operator
preferences will impact the final choices, especially where no
technology shows a clear economic advantage.
In order to determine what systems will generate the 15%
before tax return threshold, the $6.50/B development cost
constraint was applied to the TIC results. Figure 8 is the same as
Figure 6 with a range of reserve sizes shown on the right hand
vertical axis that are directly linked to the TIC values on the
left axis by the $6.50/B multiplier. Recall that the $6.50/B
constraint correlates to 200 MMB recoverable reserves at 3,000 B/D
initial well production rate. The results in Figure 8 will over
estimate reserve requirements for reserves less than 200 MMB and
production rates greater than 3,000 B/D.
The combination of reserve sizes and well counts in Figure 8
creates a set of curves representing lines of constant reserves per
well (i.e., reserve size divided by well count equals reserves per
well) . Along each such line, the combination of water depth, well
count, and reserve size should generate a 15% before tax return.
To the left of each curve, the same combination of water depth and
reservoir size would generate greater returns while those to the
right would generate lower returns.
Another way to interpret Figure 8 is to consider that for a
given water depth, there are a number of economically viable
systems depending on how much oil can be drained from each well.
The larger the drainage volume per well, the fewer the development
wells and the smaller the processing capacity that will be
required, and the more viable the development.
172
Note that a different $/B TIC constraint can be substituted to
reflect a different production rate (Figure 3), a different hurdle
rate (Figure 4), a different drilling rate (Figure 5), or a
combination of the above. Also, a new set of curves can be
constructed for a different reserve size (Figure 2) .
The above analysis indicates that fields in the 75 MMB to 150
MMB range warrant development, even in very deep water. These
results confirm the contention of other authors that deepwater
reservoirs must produce better than those on the GOM shelf.
Operators proceeding with developments today believe production
rates will be in the range of 3,000 B/D and higher, with reserves
per well of 5 MMB/W or higher.
Cost and Technology Trends
The TIC of a development can be divided into three broad cost
categories: the drilling and completion (D&C) of the wells; the
production system; and the transportation system that brings the
product back to existing infrastructure. Technology and commercial
factors will influence the future economic trends in each of these
cost categories.
Figure 9 shows the TIC breakdown for the same well count and
production rate in two water depths and two offset distances (i.e.,
length of pipeline). The 2,000 ft systems are both CPT's. The
4 , 000 ft systems are both FPS ' s though TLP systems would be
comparable since a new-build hull is assumed for the FPS.
D&C costs are a function of the number, depth and spacing of
wells (geological factors) , lease rate of the drilling rig
(commercial factor) , and drilling rate (technological factor) . The
rate of drilling impacts both development costs and the present
value of reserves in the ground (i.e., what costs you can afford).
Operators have already incorporated improved drilling technologies
in order to optimize their drilling program. Only incremental
improvements can be anticipated in drilling rates in the near term.
All the deepwater development scenarios assumed that the
drilling the initial wells were drilled with a leased floating
drilling unit prior to the arrival of the permanent production
facilities. The cost of this unit is a major contributor to D&C
costs. However, the day rate (i.e., lease cost) charged for these
rigs is already below the rate required to replace such a unit
given the current costs of rig construction. The point to consider
here is that day rates on deepwater floating drilling units are not
likely to come down, and will probably go up in the long term as
replacement rigs are required.
The transportation cost category, shown in Figure 9, varies
with pipeline length as would be expected. With the advent of
technologies such as "J Lay", the methods and equipment exist to
lay long deepwater pipelines. Cost saving improvements will
evolve, such as faster pipe joining techniques, but the basic
technologies exist today.
173
The limited worldwide demand for deepwater pipeline
construction services has limited their supply. The unit costs of
these services can not be expected to decline until greater demand
occurs, especially local demand that warrants the long-term local
deployment of competing deepwater construction vessels.
The last TIC category is production systems. Figure 10 shows
a further breakdown of the production system costs for the 4,000 ft
water depth/50 mile offset case from Figure 9. The production
system in this case is an FPS and represents approximately 48% of
the TIC, or about $3.12/B for the $6.50/B base case. The topsides
facilities (i.e., process and auxiliary systems) represent 24% of
the production system (i.e., 12% of TIC). They are primarily a
function of process capacity, and would not change greatly whether
on a CPT or TLP. Technology developments will not greatly impact
the process facility category.
The subsea facilities represent seafloor eguipment and the
systems reguired to operate that eguipment. In this example, they
represent 29% of the production system (i.e., 14% of TIC).
Technology development in this category revolves around improving
reliability and maintenance methods, as well as reducing initial
capital costs. One area of significant cost reduction is leasing
rather than purchasing maintenance eguipment. Due to efforts such
as DeepStar, the operators are moving towards common design
features that allow reuse of maintenance eguipment among several
operators1 fields. This and other improvements may reduce subsea
facilities costs about 10%, or about $.09/B for the $6.50/B base
case.
The final cost category is where there is a great deal of
technology development and rethinking the problem in general. The
platform facilities comprise all systems that support the topside
facilities and connect them to the producing wells and the export
transportation systems (i.e., pipeline). The category represents
47% of the production system cost, or 23% of the TIC, and
represents about $1.47/B for the $6.50/B base case. Examples of
some approaches being considered to reduce this cost are:
Building a shallow water platform (i.e., low cost) for
topside facilities, with minimal, or no, topside
facilities at the field site.
Using floating vessels such as the spar buoys that
represent less total steel weight than alternative
systems in deep water.
Converting existing marine eguipment; this was already
discussed but is mentioned again because there will be
specific opportunities that can be exploited.
The level of cost reduction resulting from any of these
technological developments is hard to guantify. The potential
exists to impact the platform facility area by about 25%, or about
$.37/B in the $6.50 base case.
174
Finally, a significant way of reducing the TIC is to use
existing process facilities on a neighboring platform. This is
generally called a tie-back approach, and can eliminate, or greatly
reduce, the production system costs without adversely effecting the
D&C and transportation costs. There are technology developments
involved in this area, some of which are being pursued in the
DeepStar program. However, a tie-back approach may delay
development of certain deepwater fields until processing capacity
becomes available.
175
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PoslOfficv Box 4574
Brown & Root Seaflo Houston, tx 77210-1574
October 29, 1993
Honorable Solomon P. Ortiz
U.S. House of Representatives
Committee on Merchant Marine and Fisheries
Room 1334, Longworth House Office Building
Washington, D.C. 20515-6230
Subject: Hearing on Offshore Oil and Gas Incentives RE:HR 1282
Dear Chairman Ortiz:
The following is our response to the questions your
subcommittee asked in regards to the above reference hearing. The
answers pertain specifically to the engineering and construction
phase of an offshore development.
Does deep water or frontier area drilling and production require
anv additional environmental safeguards?
We are aware of one environmental safeguard that is required
by current regulation for drilling and construction operations in
deep water that is additional to what is done in shallow water:
protection of chemosynthetic communities on the seafloor. The
Mineral Management Service regulations on this matter are given in
NTL 388-11 which became effective February 1, 1989. These
regulations specify "..measures to detect and protect deepwater
chemosynthetic communities" in water depths greater than 400 m
(i.e., deep water).
If there are anv. what are your companies doing to address these
safeguards?
In water depths less than 400 m, equipment such as a side scan
sonar and a sub-bottom profiler use acoustic methods to identify
features on the seafloor and just below the seafloor. Acoustic
methods of survey currently lack the resolution required to
conclusively identify seafloor features. When a feature is thought
to pose a potential hazard to pipelines, platforms or mooring
anchors, further investigations may be conducted by divers or
Remotely Operated Vehicles (ROV's) using optical camera equipment
to take pictures in order to conclusively identify the feature.
A Halliburton Company
186
The NTL 388-11 regulations require, in water depths greater
than 400 m, conclusive identification of ail seaf loor features that
could be disturbed by operations related to the drilling and
production of oil & gas reserves in order to determine the possible
presence of chemosynthetic communities. In practice this means
features identified by traditional bottom survey methods (e.g.,
side scan and sub-bottom profiler) must be further investigated by
ROV's using optical camera equipment to make sure no chemosynthetic
communities are present. If such communities are deemed present,
pipelines, foundations and mooring anchors are carefully located
elsewhere. The current regulation causes the additional expense
for ROV survey's of seaf loor features that would otherwise not pose
a danger to the production operation.
Has there been any research completed to address this issue?
The industry is continually improving the quality of both
acoustic and optical survey equipment. For example, underwater
laser systems are becoming available that provide better optical
resolution of seaf loor features. Also, experience will lead to
more precise interpretation of acoustic survey records regarding
the presence of chemosynthetic communities.
I hope the above information is of assistance to you in your
hearings. Brown & Root/Halliburton continues its technology
research aimed at the offshore industry's needs for cost
effectiveness, environmental protection, and human safety.
Sincerely,
James F. 0' Sullivan
Manager, Brown & Root Seaflo
187
TESTIMONY OF
MYRON J. RODRJGUE
VICE PRESIDENT AND GENERAL MANAGER
AKER GULF MARINE
BEFORE THE
OCEANOGRAPHY, GULF OF MEXICO AND OCS SUBCOMMITTEE
MERCHANT MARINE AND FISHERIES COMMITTEE
SEPTEMBER 14, 1993
188
TESTIMONY OF
MYRON J. RODRIGUE
VICE PRESIDENT AND GENERAL MANAGER
AKER GULF MARINE
BEFORE THE
OCEANOGRAPHY, GULF OF MEXICO AND OCS SUBCOMMITTEE
MERCHANT MARINE AND FISHERIES COMMITTEE
SEPTEMBER 14, 1993
Good afternoon Mr. Chairman and members of the Subcommittee. I appreciate the
invitation to testify. My name is Myron J. Rodrigue. I am Vice President and General
Manager of Aker Gulf Marine, a Texas general partnership. We operate two fabrication
yards, located in Ingleside and Aransas Pass, Texas, to service the offshore oil and gas
industries.
Our company is a relative new comer to the industry. In 1984, our parent company, Peter
Kiewit Sons', Inc., investigated the offshore fabrication market and determined that
development of the OCS was an area which would experience growth and a need for
additional capacity for deep water platform construction.
After opening our doors in November of 1984, we secured a contract to fabricate Mobil's
Green Canyon Block 18 structure. At the same time, we formed a Joint venture with a
West Coast firm to bid Shell's Bullwinkle structure. This joint venture was successful in
securing the contract. Fabrication of Bullwinkle, to date the world's largest fixed offshore
structure, began in the summer of 1985. This project took three years to build. Together
with the Mobil job and several smaller projects, our total employment reached 1200. If we
include subcontractors working directly for us and our clients, total employment at our
189
facilities was over 1600. The point is that initiatives for offshore development mean jobs
for the United States.
I became Vice President and General Manager in December 1987, just six months before
loadout of the Bullwinkle structure. At that time, our total craft employment was down
to approximately 200.
During my first two years as General Manager, my priorities were quite diverse. One was
to determine the lowest cost option to shut down our business. This was a charge from our
upper management. Another was to secure new work to keep our business going.
As you can see from the attached historic manpower graph, our business is quite cyclical.
It is quite difficult to justify the capital investment required to service the deep water
sector of the offshore industry when the market is so unpredictable. This unpredictability
is not because our clients are unwilling to explore and develop our resources.
We have invested over 50 million dollars in our plant and equipment, almost all of this in
the first three years. Because of the unique construction required for these platforms, we
have also spent a great deal of time and money training a work force capable of producing
the quality levels expected by our clients.
As noted earlier in Mr. Stewart's testimony, our industry has lost 450,000 jobs in the past
decade. If you consider the Bullwinkle project alone, it created an average of 600 jobs over
three years for us in South Texas. Additionally, direct project procurements were made
190
in 33 of the 50 states as shown on the attached drawing. When the expenditures of our
indirect suppliers are considered, undoubtedly the economic impact touched almost every
state in the union. A predictable OCS development will produce jobs across the United
States, jobs that are not just local to the coastal states.
Deep water development is not only good for reducing our independence on imported
energy, it is definitely without a doubt job-creating and economically stimulating.
We need positive, secure, uninterrupted incentives to allow long-term exploration and
development to stimulate an industry which can be productive and a positive influence on
the security and standard of living of the American people.
In closing, the petroleum industry can provide our nation's domestic energy requirements.
Producing this domestic energy will strengthen our economy by generating new jobs,
allowing the return to work of those trained workers who lost their jobs during the past
decade, stemming the flow of dollars to buy foreign energy, and creating additional
revenues for the federal treasury. At the same time, it will help President Clinton meet
his objectives of increasing the use of natural gas for its environmental benefits and as a
means of reducing our use of foreign petroleum.
Thank you for hearing my testimony.
191
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103d CONGRESS
1st Session
H.R.1282
To provide enhanced energy security through incentives to explore and develop
frontier areas of the Outer Continental Shelf and to enhance production
of the domestic oil and gas resources in deep water areas of the Outer
Continental Shelf.
IN THE HOUSE OF REPRESENTATIVES
March 10, 1993
Mr. Fields of Texas (for himself, Mr. Tauzin, Mr. Young of Alaska, Mr.
Livingston, and Mr. Laughlin) introduced the following bill; which was
referred jointly to the Committees on Natural Resources and Merchant
Marine and Fisheries
A BILL
To provide enhanced energy security through incentives to
explore and develop frontier areas of the Outer Continen-
tal Shelf and to enhance production of the domestic
oil and gas resources in deep water areas of the Outer
Continental Shelf.
1 Be it enacted by the Senate and House of Representa-
2 tives of the United States of America in Congress assembled,
3 SECTION 1. SHORT TITLE.
4 This Act may be cited as the "Outer Continental
5 Shelf Enhanced Exploration and Deep Water Incentives
6 Act".
194
2
1 SEC. 2. AMENDMENTS TO THE OUTER CONTINENTAL
2 SHELF LANDS ACT.
3 (a) Incentives. — Section 8(a)(3) of the Outer Con-
4 tinental Shelf Lands Act (43 U.S.C. 1337(a)(3)) is
5 amended to read as follows:
6 "(3)(A) The Secretary, at his own discretion or on
7 petition of a lessee, in order —
8 "(i) to promote development and new produc-
9 tion on producing or nonproducing leases, through
10 primary, secondary, or tertiary recovery means; or
1 1 "(ii) to encourage production of marginal or un-
12 economic resources on producing or nonproducing
13 leases, which may include the use of primary, sec-
14 ondary, or tertiary recovery means,
15 may reduce, suspend, or eliminate any royalty or net profit
16 share set forth in the leases. In the case of a petition of
17 a lessee, the Secretary shall make a final determination
18 under this subparagraph within 6 months after the
19 submittal of such petition.
20 "(B)(i) Notwithstanding any other provision of this
21 Act, except as provided in clauses (ii) and (iii) of this sub-
22 paragraph, no royalty payment shall be due on new pro-
23 duction from any lease located in water depths of 200 me-
24 ters or greater until the capital costs directly related to
25 such new production have been recovered by the lessee out
26 of the proceeds from such new production.
•HR IMS m
195
3
1 "(ii) Notwithstanding clause (i), in any month daring
2 which the arithmetic average of the closing prices for the
3 earliest delivery month on the New York Mercantile Ex-
4 change for light Sweet crude oil exceeds $28.00 per bar-
5 rel, any production of oil described in clause (i) shall be
6 subject to royalties at the lease stipulated rate.
7 "(iii) Notwithstanding clause (i), in any month dur-
8 ing which the arithmetic average of the closing prices for
9 the earliest delivery month on the New York Mercantile
10 Exchange for natural gas exceeds $3.50 per million Brit-
1 1 ish thermal units, any production of natural gas described
12 in clause (i) shall be subject to royalties at the lease stipu-
13 lated rate.
14 "(iv) The prices referred to in clauses (ii) and (iii)
15 of this subparagraph shall be changed during any calendar
16 year after 1993 by the percentage if any by which the
17 consumer price index changed during the preceding cal-
18 endar year, as defined in section 111(f)(4) of the Internal
19 Revenue Code of 1986.
20 "(v) Nothing in this subparagraph shall be construed
21 to affect any requirement under this section to pay bonus
22 bids.
23 "(vi) For purposes of this subparagraph —
24 "(I) the term 'capital costs' shall be defined by
25 the Secretary, shall include exploration costs in-
•HR 1382 IH
196
4
1 curred after the acquisition of the lease and develop-
2 ment and capital production costs directly related to
3 new production, shall not include any amounts paid
4 as bonus bids or paid as royalties pursuant to clause
5 (ii) or (iii), and shall be adjusted to reflect changes
6 in the consumer price index, as defined in section
7 111(f)(4) of the Internal Revenue Code of 1986; and
8 "(II) the term 'new production' means any pro-
9 duction from a lease from which no royalties have
10 been due on production, other than test production,
1 1 prior to the date of the enactment of the Outer Con-
12 tinental Shelf Enhanced Exploration and Deep
13 Water Incentives Act, or any production resulting
14 from lease development activities under a develop-
15 ment and production plan approved by the Secretary
16 under section 25 after the date of the enactment of
17 the Outer Continental Shelf Enhanced Exploration
18 and Deep Water Incentives Act.".
19 (b) Frontier Areas. — Section 18 of the Outer Con-
20 tinental Shelf Lands Act (43 U.S.C. 1344) is amended
21 by adding at the end the following new subsection:
22 "(i) The Secretary shall, in each leasing program pre-
23 pared under this section, designate as frontier areas por-
24 tions of the outer Continental Shelf, if any, with respect
25 to which the Secretary will exercise authority under sec-
•HR 1288 IH
197
5
1 tion 8(a)(3)(A) to reduce, suspend, or eliminate the re-
2 quirement to pay royalties. Any such designation shall in-
3 dude a full description of the terms of such reduction, sus-
4 pension, or elimination. In designating frontier areas
5 under this subsection, the Secretary shall take into consid-
6 eration the increased capital costs associated with explo-
7 ration and development in coastal or marine environments,
8 including arctic environments, with special environmental
9 protection requirements.".
10 SEC. 3. REGULATIONS.
11 (a) Incentives. — The Secretary shall, within 180
12 days after the date of the enactment of this Act, issue
13 such rules and regulations as are necessary to implement
14 the amendment made by section 2(a).
15 (b) Frontier Areas. — The Secretary shall, within
16 1 year after the date of the enactment of this Act, issue
17 regulations defining the term "frontier area" for purposes
18 of carrying out section 18(i) of the Outer Continental
19 Shelf Lands Act.
o
•HR 1282 IH
198
PREPARED STATEMENT
OF
SHELL OIL COMPANY
On the Outer Continental Shelf Enhanced Exploration and
Deepwater Incentives Act, H.R. 1282
Before the U.S. House of Representatives Oceanography, Gulf
of Mexico, and the Outer Continental Shelf Subcommittee
of the
Committee on Merchant Marine and Fisheries
September 14, 1993
For further information,
please contact:
Jim Rich
Shell Oil Company
Washington Office
1401 I Street, N.W.
Suite 1030
Washington, D.C. 20005
(202) 466-1425
199
PREPARED STATEMENT
OF
SHELL OIL COMPANY
Mr. Chairman and Members of the Subcommittee:
Shell Oil Company, on behalf of its two domestic
exploration and production subsidiaries, Shell Offshore Inc.
headquartered in New Orleans, Louisiana and Shell Western E&P
Inc. headquartered in Houston, Texas, appreciates this
opportunity to present its views in support of H.R. 1282, the
Outer Continental Shelf Enhanced Exploration and Deepwater
Incentives Act, which would provide a royalty holiday until
investment costs are recouped for projects in 200+ meters
(656+ feet) of water.
A major focus of Shell's exploration and production
activities is in the domestic offshore, particularly the Gulf
of Mexico, where we have been producinq since the 1940 's.
Shell holds interests in over 1,000 Gulf of Mexico tracts and
is one of the larqest leaseholders in the Gulf of Mexico. In
addition, we have produced more hydrocarbons than any other
company in the Gulf of Mexico — almost two billion barrels
of oil and ten trillion cubic feet of natural qas throuqh
1990, or 13 percent of the total hydrocarbons produced.
Technoloqy has been the key to this performance. Recent
advances in seismic acquisition and processinq technoloqy
coupled with expertise in inteqrated interpretation have
2
200
allowed us to find and delineate hydrocarbon accumulations
with greater accuracy than ever before. These technology
advances, particularly three- dimensional seismic techniques,
have led to a re-evaluation of many producing fields along
the continental shelf. Some exploratory and redevelopment
work has already taken place in this area. Further
re-evaluation along the shelf is anticipated in the future.
In addition, Shell's long-term commitment to the
development of leading edge deepwater drilling and structural
engineering technology has allowed us to take a lead role in
the deep and ultra-deep waters of the Gulf of Mexico, setting
numerous drilling and production records in the process.
These technology advances have resulted in the opening of the
deepwater frontier for exploration and development. The
1,200 to 1,500 foot (366 to 457 meter) water depth is
generally considered the transition zone between conventional
fixed platforms and non-conventional deepwater production
systems (tension leg platforms, compliant towers, floating
production systems, and subsea systems). The vast majority
of Shell's exploration and development activities are
concentrated in this latest of deepwater frontiers, where we
believe large hydrocarbon accumulations are located. The
following comments focus on the need for economic incentives
in this area.
In the past nine years, we have drilled 42 exploratory
wells on 32 deepwater prospects, setting in 1987 the world
201
deepwater drilling record upon completion of a well on Gulf
of Mexico Mississippi Canyon Block 657 in water 1.4 miles
(2,293 meters or 7,520 feet) deep. Based on what we know
today, Shell is confident this new deepwater frontier holds
significant reserve potential as evidenced by our major
announced discoveries in the deeper Gulf of Mexico waters —
Bull winkle, Auger, and Mars.
Bullwinkle is located in 1,353 feet (412 meters) of
water on Green Canyon Block 65, about 150 miles southwest of
New Orleans. Permanent production facilities were installed
in August 1991; and in 1992, the field was producing at an
average rate of 52,000 barrels of crude oil and 71 million
cubic feet of natural gas per day. Indicating the importance
of our deepwater discoveries, daily production from
Bullwinkle by 1992 was eguivalent to about 12 percent of our
domestic crude oil production.
Auger, a $1.2 billion development project, is located in
2,860 feet (872 meters) of water on Garden Banks Block 426,
some 214 miles southwest of New Orleans. Tension leg
platform installation is scheduled in late 1993 with
production beginning shortly thereafter. Production is
expected to peak at rates of 46,000 barrels of oil and 125
million cubic feet of gas per day. We have estimated Auger
total ultimate recovery at about 220 million barrels of oil
and gas eguivalent.
In May 1992, we announced a potentially major new
202
deepwater discovery on the Mars prospect, about 130 miles
southeast of New Orleans. Located in water over half a mile
(3,100 feet or 945 meters) deep, this discovery — if
developed as a commercial field — would establish a new Gulf
of Mexico water depth production record. While we are not
prepared to provide a specific range of volumes, our
evaluation to date indicates that Mars will significantly
surpass in ultimate recovery our Auger prospect. A Mars
development decision could be made as early as late 1993.
The need for economic incentives exists in the deepwater
Gulf of Mexico frontier despite development of projects such
as Bullwinkle and Auger. Both Bullwinkle and Auger contain
extremely large hydrocarbon accumulations situated and of a
quality which are economic to produce at today's prices.
Undoubtedly other large deepwater Gulf of Mexico fields will
be justified in the years ahead, possibly Mars. But how many
deepwater Gulf of Mexico prospects exist the size and caliber
of Auger or Mars? Historically, there have been very few
Gulf of Mexico shelf fields the size of these discoveries.
The majority of Gulf of Mexico fields are in the 2 - 150
million barrel range with only a limited number of fields in
excess of 300 million barrels. If deepwater follows shallow
water trends, the vast majority of deepwater prospects would
be expected to be smaller than Auger and Mars as exploration
expands. Logically, this is what one would expect since
industry obviously is exploring and developing what it
203
believes today to be its prime acreage first. Shell is
systematically drilling its deepwater leasehold. However, we
are skeptical about full development of the deepwater Gulf of
Mexico potential for the reasons that follow.
Deepwater economics differ significantly from shallow
water. Deepwater projects require large up-front exploration
expenditures and prospect delineation costs. Once
delineated, the capital investment to develop a typical
deepwater project can easily exceed $1 billion, as much as
ten times the cost of shallow water projects. Because of
facility design, construction, and development complexities,
it takes two to three times as long to begin production from
a deepwater project versus a shallower water project. In
addition, the hydrocarbon recovery period typically is much
longer — about ten years longer to the mid-point of
recovery. These factors result in a substantial deferment of
return on investment. As a consequence of this deferment,
the present dollar value of gas and oil produced in the
deepwater is significantly less than shallower water
production. Additional complexities and uncertainties
related to reservoir performance, long-term natural gas and
crude oil prices, hydrocarbon quality, availability of
hydrocarbon transportation facilities and support
infrastructure, and project cost uncertainties contribute to
the economic risk of deepwater projects. Consequently, many
prospects will not be economically attractive under current
204
price projections, especially given the production risks
associated with this step into the ultra-deepwater and the
marginal profitability of many of the prospects. Economic
incentives, therefore, will be needed to accelerate and
maximize development of these reserves.
H.R. 1282, the Outer Continental Shelf Enhanced
Exploration and Deepwater Incentives Act, should stimulate
investment in new domestic exploration and production
activities by providing a royalty holiday until investment
costs are recouped for projects in 200+ meters (656+ feet) of
water. The proposal is much needed and is definitely a step
in the right direction. While we wholeheartedly support the
thrust of H.R. 1282, we do have some suggestions to improve
the effectiveness of this legislation and its ability to meet
the bill's objective of providing enhanced energy security
through incentives to explore and develop frontier areas of
the Outer Continental Shelf and to enhance production of the
domestic oil and gas resources in deepwater areas of the
Outer Continental Shelf.
First, we recommend that it be amended to clarify that
all investment costs incurred in a "phased" development
program qualify for royalty relief. This clarification is
important to Shell because our approach to the development of
some deepwater discoveries, if economical, would be in
phases. This type of development would be necessary because
of the billion dollar plus up-front capital expenditures
205
required to construct and install full permanent facilities
in water depths of 1500 feet (457 meters) or greater. As
currently envisioned, under a phased development scenario,
the initial phase would involve installation of a small
structure from which initial production wells would be
drilled and produced to test reservoir performance. If the
reservoir produces as expected, we would then proceed to the
next phase — construction and installation of permanent
production facilities. If all production horizons cannot be
reached from these facilities, subsequent phases —
construction and installation of additional production
facilities — might be required. In these water depths, the
higher capital outlays are found in the latter phases. If
this legislation is to encourage development at this water
depth, investment costs in these latter phases must qualify
for royalty relief.
Secondly, we strongly recommend that the legislation be
amended to include new development activities on leases which
are producing prior to enactment of H.R. 1282. As indicated
earlier, new three dimensional seismic technology has allowed
industry to re-evaluate many known and producing Gulf of
Mexico fields along the continental shelf. New production
horizons untapped by existing platforms and wells are being
found. We expect the same result when this technology is
applied to leases on production today in approximately 1,000+
feet (305+ meters) of water. Royalty relief until investment
206
costs are recouped should provide the encouragement to allow
a number of these projects to go forward.
Again, H.R. 1282 is a step in the right direction to
encourage development of deepwater potential. However, a
broad range of incentives will be needed if the Nation is to
take full advantage of this significant new source of
domestic oil and gas. A June 24, 1993 DRI/McGraw-Hill
report, "National Economic Impacts of an Oil/Gas Production
Tax Credit to Stimulate Deepwater Exploration and
Development*' , presented the results of a DRI /McGraw-Hill
economic analysis of the potential impacts resulting from
domestic Gulf of Mexico deepwater oil and gas exploration and
development stimulated by a federal production tax credit
incentive of $5 per barrel oil equivalent. Such an incentive
was contained in bill S. 403, introduced February 17, 1993 by
Senator Breaux. An assumed volume of 9 billion barrels oil
equivalent of incremental deepwater reserves developed as a
result of the incentive, as well as resulting production
(peaks at 860,000 barrels oil equivalent per day), and
investment and operating cost information were supplied DRI
by selected companies engaged in deepwater exploration and
development. Energy prices were based on the National
Petroleum Council's 1992 natural gas study "low reference
case". The study covered a 25-year time frame (through
2017). The economic impacts on specific Gulf coast region
states (Louisiana, Texas, Oklahoma, Alabama, and Mississippi)
207
were also examined in an adjunct report (dated July 9, 1993).
Among the key conclusions of the study are:
- Up to 100,000 new jobs created near term (by 1998)
with 60,000 to 80,000 jobs sustained through the end
of the study period.
- Annual real GDP increased by $4 - $8 billion (1987
dollars) in 1998, increasing to $20 billion by 2017.
- Cumulative federal revenues increased $6 - $10 billion
by 1998 (nominal dollars) with total net revenues
reaching $330 - $375 billion by 2017 (net of the tax
incentive) .
- Federal debt reduced $5 - $9 billion (nominal dollars)
by 1998 with total debt reductions reaching $213 -
$234 billion by 2017.
- Annual foreign trade balance improved by $23 billion
in 2017 (nominal dollars).
The DRI/McGraw-Hill study clearly indicates that a $5 per
barrel oil equivalent production tax credit incentive would
result in a win-win economic benefit for the Nation as a
whole and the industry while adding significantly to the
domestic supply of oil and gas. The productior tax credit
should be given serious consideration as one of a broad range
of incentives which will be needed to accelerate development
of the deepwater Gulf of Mexico, create jobs, stimulate the
economy, reduce the trade deficit and sustain Gulf of Mexico
production into the next century.
10
o
KK.UBL,C L|BRARY
3 9999 05982 615 "4
ISBN 0-16-043350-9
9 780160N433504
90000
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